Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbols	Name of exchange on which registered
Class A common stock, par value $0.01 per share	SPKE	The NASDAQ Global Select Market
8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share	SPKEP	The NASDAQ Global Select Market

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•	changes in commodity prices;

•	the sufficiency of risk management and hedging policies and practices;

•	the impact of extreme and unpredictable weather conditions, including hurricanes and other natural disasters;

•	federal, state and local regulations, including the industry's ability to address or adapt to potentially restrictive new regulations that may be enacted by public utility commissions;

•	our ability to borrow funds and access credit markets;

•	restrictions in our debt agreements and collateral requirements;

•	credit risk with respect to suppliers and customers;

•	changes in costs to acquire customers as well as actual attrition rates;

•	accuracy of billing systems;

•	our ability to successfully identify, complete, and efficiently integrate acquisitions into our operations;

•	significant changes in, or new changes by, the independent system operators (“ISOs”) in the regions we operate;

•	competition; and

•	the “Risk Factors” in this Annual Report, and in our quarterly reports, other public filings and press releases.

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PART I.

Items 1 & 2. Business and Properties

General

We are an independent retail energy services company founded in 1999 and are organized as a Delaware corporation that provides residential and commercial customers in competitive markets across the United States with an alternative choice for their natural gas and electricity. We purchase our electricity and natural gas supply from a variety of wholesale providers and bill our customers monthly for the delivery of electricity and natural gas based on their consumption at either a fixed or variable price. Electricity and natural gas are then distributed to our customers by local regulated utility companies through their existing infrastructure.

Our business consists of two operating segments:

•	Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial transactions with market counterparties and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts.

•	Retail Natural Gas Segment. In this segment, we purchase natural gas supply through physical and financial transactions with market counterparties and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts.

Our Operations

As of December 31, 2019, we operated in 94 utility service territories across 19 states and the District of Columbia and had approximately 672,000 residential customer equivalents (“RCEs”). An RCE is an industry standard measure of natural gas or electricity usage with each RCE representing annual consumption of 100 MMBtu of natural gas or 10 MWh of electricity. We serve natural gas customers in fifteen states (Arizona, California, Colorado, Connecticut, Florida, Illinois, Indiana, Maryland, Massachusetts, Michigan, Nevada, New Jersey, New York, Ohio and Pennsylvania) and electricity customers in twelve states (Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Ohio, Pennsylvania and Texas) and the District of Columbia using seven brands (Electricity Maine, Electricity N.H., Major Energy, Provider Power Mass, Respond Power, Spark Energy, and Verde Energy).

Customer Contracts and Product Offerings

Fixed and variable-price contracts

We offer a variety of fixed-price and variable-price service options to our natural gas and electricity customers. Under our fixed-price service options, our customers purchase natural gas and electricity at a fixed price over the life of the customer contract, which provides our customers with protection against increases in natural gas and electricity prices. Our fixed-price contracts typically have a term of one to two years for residential customers and up to three years for commercial customers, and most provide for an early termination fee in the event that the customer terminates service prior to the expiration of the contract term. In a typical market, we offer fixed-price electricity plans for 6, 12 and 24 months and fixed-price natural gas plans from 12 to 24 months, which may or may not provide for a monthly service fee and/or a termination fee, depending on the market and customer type. Our variable-price service options carry a month-to-month term and are priced based on our forecasts of underlying commodity prices and other market factors, including the competitive landscape in the market and the regulatory environment, and may also include a monthly service fee depending on the market and customer type. We also offer variable-price natural gas and electricity plans that offer an introductory fixed price that is generally applied for a certain number of billing cycles, typically two billing cycles in our current markets, then switches to a variable price based on market conditions. Our variable plans may or may not provide for a termination fee, depending on the market and customer type.

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The fixed/variable splits of our RCEs were as follows as of December 31, 2019:

Green products and renewable energy credits

We offer renewable and carbon neutral (“green”) products in certain markets. Green energy products are a growing market opportunity and typically provide increased unit margins as a result of improved customer satisfaction and less competition. Renewable electricity products allow customers to choose electricity sourced from wind, solar, hydroelectric and biofuel sources, through the purchase of renewable energy credits (“RECs”). Carbon neutral natural gas products give customers the option to reduce or eliminate the carbon footprint associated with their energy usage through the purchase of carbon offset credits. These products typically provide for fixed or variable prices and generally follow the terms of our other products with the added benefit of carbon reduction and reduced environmental impact. We currently offer renewable electricity in all of our electricity markets and carbon neutral natural gas in several of our gas markets. As of December 31, 2019, approximately 37% of our customers utilized green products.

In addition to the RECs we purchase to satisfy our voluntary requirements under the terms of our green contracts with our customers, we must also purchase a specified number of RECs based on the amount of electricity we sell in a state in a year pursuant to individual state renewable portfolio standards. We forecast the price for the required RECs at the end of each month and incorporate this cost component into our customer pricing models.

Customer Acquisition and Retention

Our customer acquisition strategy consists of customer growth obtained through traditional sales channels complemented by customer portfolio and business acquisitions. We make decisions on how best to deploy capital based on a variety of factors, including cost to acquire customers, availability of opportunities and our view of attractive commodity pricing in particular regions.

Organic Growth

We use organic sales strategies to both maintain and grow our customer base by offering competitive pricing, price certainty, and/or green product offerings. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices to the price offered by the local regulated utility. We then determine if there is an opportunity in a particular market based on our ability to create a competitive product on economic terms that provides customer value and satisfies our profitability objectives. The attractiveness of a product from a consumer’s standpoint is based on a variety of factors, including overall pricing, price stability, contract term, sources of generation and environmental impact and whether or not the contract

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provides for termination and other fees. Product pricing is also based on several other factors, including the cost to acquire customers in the market, the competitive landscape and supply issues that may affect pricing.

Once a product has been created for a particular market, we then develop a marketing campaign using a combination of sales channels. We identify and acquire customers through a variety of sales channels, including our inbound customer care call center, outbound calling, online marketing, opt-in web-based leads, email, direct mail, door-to-door sales, affinity programs, direct sales, brokers and consultants. For residential customers, we primarily use indirect sales brokers, web based solicitation, door-to-door sales, outbound calling, and other methods. For 2019, the largest channels were outbound telemarketing, door-to-door sales, and web-based sales. For C&I customers, which are typically larger and have greater natural gas and electricity requirements, we typically use brokers or direct marketing to obtain these customers. At December 31, 2019, our customer base was 61% residential and 39% C&I customers. In our sales practices, we typically employ multiple vendors under short-term contracts and have not entered into any exclusive marketing arrangements with sales vendors. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve targeted growth and manage customer acquisition costs. We strive to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods.

Acquisitions

We actively monitor acquisition opportunities that may arise in the domestic acquisition market, and seek to acquire both portfolios of customers as well as retail energy companies utilizing some combination of cash and borrowings under our Senior Credit Facility, the issuance of common or preferred stock, or other financing arrangements. Historically, our customer acquisition strategy has been executed using both third parties and through affiliated relationships. See “—Relationship with our Founder and Majority Shareholder” for a discussion of affiliate relationships.

The following table provides a summary of our acquisitions over the past five years:

	Company / Portfolio	Date Completed	RCEs	Segment	Acquisition Source
	Customer Portfolio	February 2015	12,500	Electricity	Third Party
	CenStar Energy Corp.	July 2015	65,000	Natural Gas Electricity	Third Party
	Oasis Power Holdings, LLC	July 2015	40,000	Natural Gas Electricity	Affiliate
	Customer Portfolio	September 2015	9,500	Natural Gas	Third Party
	Provider Companies (1)	August 2016	121,000	Electricity	Third Party
	Major Energy Companies (2)	August 2016	220,000	Natural Gas Electricity	Affiliate
	Perigee Energy, LLC	April 2017	17,000	Natural Gas Electricity	Affiliate
	Verde Companies (3)	July 2017	145,000	Electricity	Third Party
	Customer Portfolio	October 2017	44,000	Electricity	Third Party
	HIKO Energy, LLC	March 2018	29,000	Natural Gas Electricity	Third Party
	Customer Portfolio	December 2018	35,000	Natural Gas Electricity	Affiliate
	Customer Portfolio	May 2019	60,000	Natural Gas Electricity	Third Party

(1)	Included Electricity Maine, LLC, Electricity N.H., LLC, Provider Power Mass, LLC (collectively, the “Provider Companies”).

(2)	Included Major Energy Services, LLC, Major Energy Electric Services, LLC, and Respond Power, LLC (collectively, the “Major Energy Companies”).

(3)	Included Verde Energy USA, Inc.; Verde Energy USA Commodities, LLC; Verde Energy USA Connecticut, LLC; Verde Energy USA DC, LLC; Verde Energy USA Illinois, LLC; Verde Energy USA Maryland, LLC; Verde Energy USA Massachusetts, LLC; Verde Energy USA New Jersey, LLC; Verde

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Energy USA New York, LLC; Verde Energy USA Ohio, LLC; Verde Energy USA Pennsylvania, LLC; Verde Energy USA Texas Holdings, LLC; Verde Energy USA Trading, LLC; and Verde Energy Solutions, LLC (collectively, the “Verde Companies”).

Please see Item 9B. “Other Information” and Note 4 "Acquisitions" in the notes to our consolidated financial statements for a more detailed description of these acquisitions, including the purchase price, the source of funds and financing arrangements with our Founder and/or NG&E. Please see “Risk Factors" for a discussion of risks related to our acquisition strategy and ability to finance such transactions.

Retaining customers and maximizing customer lifetime value

Following the acquisition of a customer, we devote significant attention to customer retention. We have developed a disciplined renewal communication process, which is designed to effectively reach our customers prior to the end of the contract term, and employ a team dedicated to managing this renewal communications process. Customers are contacted in each utility prior to the expiration of the customer's contract. We may contact the customer through additional channels such as outbound calls or email. We also apply a proprietary evaluation and segmentation process to optimize value to both us and the customer. We analyze historical usage, attrition rates and consumer behaviors to specifically tailor competitive products that aim to maximize the total expected return from energy sales to a specific customer, which we refer to as customer lifetime value.

We actively monitor unit margins from energy sales. We use this information to assess the results of products and to guide business decisions, including whether to engage in pro-active non-renewal of lower margin customers is in the interest of the Company.

Investment in ESM

In 2016, we and eREX Co., Ltd., a Japanese company, entered into a joint venture investment in eREX Spark Marketing Co., Ltd ("ESM"). Operations for ESM began on April 1, 2016 in connection with the deregulation of the Japanese power market. As part of the agreement, we made contributions of 156.4 million Japanese Yen, or $1.4 million, for a 20% ownership interest in ESM.

In November 2019, Spark HoldCo, LLC entered into a share purchase agreement with eREX Co., Ltd. In accordance with the agreement, we sold our 20% ownership interest in ESM for $8.4 million. See Note 17 "Equity Method Investment" for further discussion.

Commodity Supply

We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets, through short- and long-term contracts. Our in-house energy supply team is responsible for managing our commodity positions (including energy procurement, capacity, transmission, renewable energy, and resource adequacy requirements) within our risk management policies. We procure our natural gas and electricity requirements at various trading hubs, city-gates and load zones. When we procure commodities at trading hubs, we are responsible for delivery to the applicable local regulated utility for distribution.

In most markets, we hedge our electricity exposure with financial products and then purchase the physical power directly from the ISO for delivery. Alternatively, we may use physical products to hedge our electricity exposure rather than buying physical electricity in the day-ahead market from the ISO. During the year ended December 31, 2019, we transacted physical and financial settlement of electricity with approximately 13 suppliers.

We are assessed monthly for ancillary charges such as reserves and capacity in the electricity sector by the ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines are necessary to protect the integrity of the grid. We attempt to estimate such amounts, but they are difficult to estimate because they are charged in arrears by the ISOs and are subject to fluctuations based on weather and other market

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conditions. Many of the utilities we serve also allocate natural gas transportation and storage assets to us as a part of their competitive choice program. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so.

We periodically adjust our portfolio of purchase/sale contracts in the wholesale natural gas market based upon continual analysis of our forecasted load requirements. Natural gas is then delivered to the local regulated utility city-gate or other specified delivery point where the local regulated utility takes control of the natural gas and delivers it to individual customer locations. Additionally, we hedge our natural gas price exposure with financial products. During the year ended December 31, 2019, we transacted physical and financial settlements of natural gas with approximately 70 wholesale counterparties.

We also enter into back-to-back wholesale transactions to optimize our credit lines with third-party energy suppliers. With each of our third-party energy suppliers, we have certain contracted credit lines, within which we are able to purchase energy supply from these counterparties. If we desire to purchase supply beyond these credit limits, we are required to post collateral in the form of either cash or letters of credit. As we begin to approach the limits of our credit line with one supplier, we may purchase energy supply from another supplier and sell that supply to the original counterparty in order to reduce our net position with that counterparty and open up additional credit to procure supply in the future. Our sales of gas pursuant to these activities also enable us to optimize our credit lines with third-party energy suppliers by decreasing our net buy position with those suppliers.

Asset Optimization

Part of our business includes asset optimization activities in which we identify opportunities in the wholesale natural gas markets in conjunction with our retail procurement and hedging activities. Many of the competitive pipeline choice programs in which we participate require us and other retail energy suppliers to take assignment of and manage natural gas transportation and storage assets upstream of their respective city-gate delivery points. In our allocated storage assets, we are obligated to buy and inject gas in the summer season (April through October) and sell and withdraw gas during the winter season (November through March). These injection and purchase obligations require us to take a seasonal long position in natural gas. Our asset optimization group determines whether market conditions justify hedging these long positions through additional derivative transactions. We also contract with third parties for transportation and storage capacity in the wholesale market and are responsible for reservation and demand charges attributable to both our allocated and third-party contracted transportation and storage assets. Our asset optimization group utilizes these allocated and third-party transportation and storage assets in a variety of ways to either improve profitability or optimize supply-side counterparty credit lines.

We frequently enter into spot market transactions in which we purchase and sell natural gas at the same point or we purchase natural gas at one location and ship it using our pipeline capacity for sale at another location, if we are able to capture a margin. We view these spot market transactions as low risk because we enter into the buy and sell transactions on a back-to-back basis. We also act as an intermediary for market participants who need assistance with short-term procurement requirements. Consumers and suppliers contact us with a need for a certain quantity of natural gas to be bought or sold at a specific location. When this occurs, we are able to use our contacts in the wholesale market to source the requested supply and capture a margin in these transactions.

Our risk policies require that optimization activities be limited to back-to-back purchase and sale transactions, or open positions subject to aggregate net open position limits, which are not held for a period longer than two months. Furthermore, all additional capacity procured outside of a utility allocation of retail assets must be approved by a risk committee. Hedges of our firm transportation obligations are limited to two years or less and hedging of interruptible capacity is prohibited.

Risk Management

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We operate under a set of corporate risk policies and procedures relating to the purchase and sale of electricity and natural gas, general risk management and credit and collections functions. Our in-house energy supply team is responsible for managing our commodity positions (including energy, capacity, transmission, renewable energy, and resource adequacy requirements) within our risk management policies. We attempt to increase the predictability of cash flows by following our hedging strategies.

Our risk committee has control and authority over all of our risk management activities. The risk committee establishes and oversees the execution of our credit risk management policy and our commodity risk policy. The risk management policies are reviewed at least annually by the risk management committee and such committee typically meets quarterly to assure that we have followed these policies. The risk committee also seeks to ensure the application of our risk management policies to new products that we may offer. The risk committee is comprised of our Chief Executive Officer and our Chief Financial Officer, who meet on a regular basis to review the status of the risk management activities and positions. Our risk team reports directly to our Chief Financial Officer and their compensation is unrelated to trading activity. Commodity positions are typically reviewed and updated daily based on information from our customer databases and pricing information sources. The risk policy sets volumetric limits on intra-day and end of day long and short positions in natural gas and electricity. With respect to specific hedges, we have established and approved a formal delegation of authority specifying each trader's authorized volumetric limits based on instrument type, lead time (time to trade flow), fixed price volume, index price volume and tenor (trade flow) for individual transactions. The risk team reports to the risk committee any hedging transactions that exceed these delegated transaction limits. A discussion of the various risks we face in our risk management activities is as follows:

Commodity Price and Volumetric Risk

Because our contracts require that we deliver full natural gas or electricity requirements to our customers and because our customers’ usage can be impacted by factors such as weather, we may periodically purchase more or less commodity than our aggregate customer volumetric needs. In buying or selling excess volumes, we may be exposed to commodity price volatility. In order to address the potential volumetric variability of our monthly deliveries for fixed-price customers, we implement various hedging strategies to attempt to mitigate our exposure.

 

Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer contracts. We use both physical and financial products to hedge our fixed-price exposure. The efficacy of our risk management program may be adversely impacted by unanticipated events and costs that we are not able to effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or availability or cost of, financial instruments that help to hedge commodity price.

Variability in customer demand is primarily impacted by weather. We use utility-provided historical and/or forward projected customer volumes as a basis for our forecasted volumes and mitigate the risk of seasonal volume fluctuation for some customers by purchasing excess fixed-price hedges within our volumetric tolerances. Should seasonal demand exceed our weather-normalized projections, we may experience a negative impact on our financial results.

From time to time, we also take further measures to reduce price risk and optimize our returns by: (i) maximizing the use of natural gas storage in our daily balancing market areas in order to give us the flexibility to offset volumetric variability arising from changes in winter demand; (ii) entering into daily swing contracts in our daily balancing markets over the winter months to enable us to increase or decrease daily volumes if demand increases or decreases; and (iii) purchasing out-of-the-money call options for contract periods with the highest seasonal volumetric risk to protect against steeply rising prices if our customer demands exceed our forecast. Being geographically diversified in our delivery areas also permits us, from time to time, to employ assets not being used

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in one area to other areas, thereby mitigating potential increased costs for natural gas that we otherwise may have had to acquire at higher prices to meet increased demand.

We utilize New York Mercantile Exchange (“NYMEX”) settled financial instruments to offset price risk associated with volume commitments under fixed-price contracts. The valuation for these financial instruments is calculated daily based on the NYMEX Exchange published closing price, and they are settled using the NYMEX Exchange’s published settlement price at their maturity.

Basis Risk

We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems around the Chicago metropolitan area, we are exposed to the risk that prices may differ between the Chicago delivery point and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are occasionally not economically feasible or available in the smaller quantities that we require.

Customer Credit Risk

Our credit risk management policies are designed to limit customer credit exposure. Credit risk is managed through participation in purchase of receivables ("POR") programs in utility service territories where such programs are available. In these markets, we monitor the credit ratings of the local regulated utilities and the parent companies of the utilities that purchase our customer accounts receivable. We also periodically review payment history and financial information for the local regulated utilities to ensure that we identify and respond to any deteriorating trends. In non-POR markets, we assess the creditworthiness of new applicants, monitor customer payment activities and administer an active collection program. Using risk models, past credit experience and different levels of exposure in each of the markets, we monitor our receivable aging, bad debt forecasts and actual bad debt expenses and continually adjust as necessary.

In territories where POR programs have been established, the local regulated utility purchases our receivables, and then becomes responsible for billing and collecting payment from the customer. In return for their assumption of risk, we receive slightly discounted proceeds on the receivables sold. POR programs result in substantially all of our credit risk being linked to the applicable utility and not to our end-use customers in these territories. For the year ended December 31, 2019, approximately 67% of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies, all of which had investment grade ratings. During the same period, we paid these local regulated utilities a weighted average discount of approximately 0.8% of total revenues for customer credit risk. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period. If our subsequent collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract.

In non-POR markets (and in select POR markets where we may choose to direct bill our customers), we manage commercial customer credit risk through a formal credit review and manage residential customer credit risk through a variety of procedures, which may include credit score screening, deposits and disconnection for non-payment. We

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also maintain an allowance for doubtful accounts, which represents our estimate of potential credit losses associated with accounts receivable from customers within these markets.

We assess the adequacy of the allowance for doubtful accounts through review of an aging of customer accounts receivable and general economic conditions in the markets that we serve. Our bad debt expense for the year ended December 31, 2019 was $13.5 million, or 1.7% of retail revenues. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for a more detailed discussion of our bad debt expense for the year ended December 31, 2019.

We do not have high concentrations of sales volumes to individual customers. For the year ended December 31, 2019, our largest customer accounted for 1% of total retail energy sales volume.

Counterparty Credit Risk in Wholesale Markets

We do not independently produce natural gas and electricity and depend upon third parties for our supply, which exposes us to wholesale counterparty credit risk in our retail and asset optimization activities. If the counterparties to our supply contracts are unable to perform their obligations, we may suffer losses, including those that occur as a result of being unable to secure replacement supplies of natural gas or electricity on a timely or cost-effective basis or at all. At December 31, 2019, approximately $0.1 million of our total exposure of $3.1 million was either with a non-investment grade counterparty or otherwise not secured with collateral or a guarantee.

Operational Risk

As with all companies, we are at risk from cyber-attacks (breaches, unauthorized access, misuse, computer viruses, or other malicious code or other events) that could materially adversely affect our business, or otherwise cause interruptions or malfunctions in our operations. We mitigate these risks through multiple layers of security controls including policy, hardware, and software security solutions. We also have engaged third parties to assist with both external and internal vulnerability scans and continually enhance awareness through employee education and accountability. As of December 31, 2019, we have not experienced any material loss related to cyber-attacks or other information security breaches.

Relationship with our Founder and Majority Shareholder

We have historically leveraged our relationship with affiliates of our founder, chairman and majority shareholder, W. Keith Maxwell III (our "Founder"), to execute our strategy, including sourcing acquisitions, financing, and operations support. Our Founder owns National Gas & Electric, LLC (“NG&E”), which was formed for the purpose of purchasing retail energy companies and retail customer books that may ultimately be resold to the Company. This relationship has afforded us access to opportunities that may not have otherwise been available to us due to our size and availability of capital.

We may engage in additional transactions with NG&E in the future and expect that any such transactions would be funded by a combination of cash, subordinated debt, or the issuance of Class A or Class B common stock. Actual consideration paid for the assets would depend, among other things, on our capital structure and liquidity at the time of any transaction. Although we believe our Founder would be incentivized to offer us additional acquisition opportunities, he and his affiliates are under no obligation to do so, and we are under no obligation to buy assets from them. Any acquisition activity involving NG&E or any other affiliate of our Founder will be subject to negotiation and approval by a special committee of our Board of Directors consisting solely of independent directors. Please see “Risk Factors” related to acquisitions and transactions with our affiliates.

Competition

The markets in which we operate are highly competitive. Our primary competition comes from the incumbent utility and other independent retail energy companies. In the electricity sector, these competitors include larger,

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well-capitalized energy retailers such as Calpine Energy Solutions, LLC, Constellation Energy Group, Inc., Direct Energy, Inc., NRG Energy, Inc., and Vistra Energy Corp. We also compete with small local retail energy providers in the electricity sector that are focused exclusively on certain markets. Each market has a different group of local retail energy providers. In the natural gas sector, our national competitors are primarily Direct Energy and Constellation Energy. Our national competitors generally have diversified energy platforms with multiple marketing approaches and broad geographic coverage similar to us. Competition in each market is based primarily on product offering, price and customer service. The number of competitors in our markets varies. In well-established markets in the Northeast and Texas we have hundreds of competitors, while in other markets the competition is limited to several participants. Markets that offer POR programs are generally more competitive than those markets in which retail energy providers bear customer credit risk.

Our ability to compete depends on our ability to convince customers to switch to our products and services, renew services with customers upon expiration of their contract terms, and our ability to offer products at attractive prices. Many local regulated utilities and their affiliates may possess the advantages of name recognition, longer operating histories, long-standing relationships with their customers and access to financial and other resources, which could pose a competitive challenge to us. As a result of our competitors' advantages, many customers of these local regulated utilities may decide to stay with their longtime energy provider if they have been satisfied with their service in the past. In addition, competitors may choose to offer more attractive short-term pricing to increase their market share.

Seasonality of Our Business

Our overall operating results fluctuate substantially on a seasonal basis depending on: (i) the geographic mix of our customer base; (ii) the relative concentration of our commodity mix; (iii) weather conditions, which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and (iv) variability in market prices for natural gas and electricity. These factors can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle.

Our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable to those supplies. This timing difference affects our cash flows, especially during peak cycles in the winter and summer months.

Natural gas accounted for approximately 15% of our retail revenues for the year ended December 31, 2019, which exposes us to a high degree of seasonality in our cash flows and income earned throughout the year as a result of the high concentration of heating load in the winter months. We utilize a considerable amount of cash from operations and borrowing capacity to fund working capital, which includes inventory purchases from April through October each year. We sell our natural gas inventory during the months of November through March of each year. We expect that the significant seasonality impacts to our cash flows and income will continue in future periods.

 

Regulatory Environment

We operate in the highly regulated natural gas and electricity retail sales industry in all of our respective jurisdictions, and must comply with the legislation and regulations in these jurisdictions in order to maintain our licenses to operate. We must also comply with the applicable regulations in order to obtain the necessary licenses in jurisdictions in which we plan to compete. Licensing requirements vary by state, but generally involve regular, standardized reporting in order to maintain a license in good standing with the state commission responsible for regulating retail electricity and gas suppliers. We believe there is potential for changes to state legislation and regulatory measures addressing licensing requirements that may impact our business model in the applicable jurisdictions. In addition, as further discussed below, our marketing activities and customer enrollment procedures

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are subject to rules and regulations at the state and federal levels, and failure to comply with requirements imposed by federal and state regulatory authorities could impact our licensing in a particular market. See "Risk Factors—We face risks due to increasing regulation of the retail energy industry at the state level."

New York

A Low-Income Order was promulgated by the New York State Public Service Commission ("NYPSC") in December of 2016 (the "Low-Income Order"), and the New York State Supreme Court, Appellate Division, Third Department ruled in September 2017 that energy service companies ("ESCOs") must proceed with returning existing low-income customers to utility service and stop enrolling new low-income customers. The ESCOs have effectively exhausted their legal remedies to appeal this matter and must now comply with the Low-Income Order. ESCOs may continue serving low income customers if those customers are enrolled in fixed arrangements with guaranteed savings or with value add inclusions (that were entered into prior to the effective date of the Low-Income Order) or if the ESCO receives a waiver from the NYPSC to provide low-income customers with guaranteed savings. The Company and its subsidiaries have been returning low-income customers to the applicable utilities as they have rolled off of their contracts. As of December 31, 2019, remaining low-income customers represent approximately 1.3% of our total RCEs in New York and 0.2% of our RCEs overall.

In December 2019, the NYPSC issued its retail energy market reset order (the “December 2019 Reset Order”), that ESCOs will be required to comply with commencing early May 2020. The December 2019 Reset Order states that ESCOs can only enroll new residential or small nonresidential customers (mass-market customers) or renew existing mass-market customer contracts for gas and/or electric service only if at least one of the following conditions is met: (1) enrollment includes a guaranteed savings over the utility price, as reconciled on an annual basis; (2) enrollment is for a fixed-rate commodity product that is priced at no more than 5% greater than the trailing 12-month average utility supply rate; (3) enrollment is for a renewably sourced electric commodity product that (a) has a renewable mix that is at least 50% greater than the ESCO’s current Renewable Energy Standard (RES) obligation, (b) the ESCO complies with the RES locational and delivery requirements when procuring RECs or entering into bilateral contracts for renewable commodity supply, and (c) there is transparency of information and disclosures provided to the customer with respect to pricing and commodity sourcing.  In addition, by June 9, 2020, all New York ESCOs are directed to essentially re-apply for licenses to serve customers in New York.

We are evaluating the potential impact of the NYPSC's December 2019 Reset Order and subsequent proceedings on our New York operations while preparing to operate in compliance with any new requirements that may come as a result of any new order promulgated by the NYPSC. Given the uncertainty of the outcome of these matters and the final requirements that may be implemented, we are unable to predict at this time the magnitude of the long-term impact on our operations in New York.

Massachusetts

In October 2018, the Attorney General for the Commonwealth of Massachusetts filed suit against another ESCO and others alleging unfair or deceptive acts or practices in violation of a consumer protections act, breach of the covenant of good faith and fair dealing, and violation of the Massachusetts Telemarketing Solicitation Act. Contemporaneously with the filing of their complaint, the Commonwealth filed for injunctive relief seeking to attach purchase of receivables program revenues owed to the ESCO as possible damages. There can be no assurance that the Commonwealth will not pursue similar claims against other ESCOs.

Other States

Recently, certain state commissions have begun efforts to restrict the ability of retail suppliers to “pass through” costs to customers associated with certain changes in law or regulatory requirements. For example, on January 22, 2019, the New Jersey Board of Public Utilities (“NJ BPU”) sent a cease and desist letter to third party suppliers (“TPS”) in New Jersey instructing that a TPS may not charge a customer rate that is higher than the fixed rate applicable during the period for which that rate was fixed. The letter notified TPS that such increases were

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prohibited and instructed TPS to refund customers amounts charged in excess of the applicable fixed rate. Parties have challenged the NJ BPU’s letter and it is not clear at this time whether refunds will be required. Similarly, the Connecticut Public Utilities Regulatory Authority (“PURA”) recently opened a docket after receiving complaints regarding increases by suppliers to certain fixed-price supplier contracts due to change in law triggers. PURA will consider whether suppliers’ actions constitute unfair and deceptive trade practices or otherwise violates applicable laws. PURA is expected to issue a declaratory ruling following its review. Depending on the outcome of these efforts in New Jersey and Connecticut, the Company may be required to assume costs that it otherwise would pass on to customers under its change in law provisions and potentially provide refunds to certain customers.

Other Regulations

Our marketing efforts to consumers, including but not limited to telemarketing, door-to-door sales, direct mail and online marketing, are subject to consumer protection regulation including state deceptive trade practices acts, Federal Trade Commission ("FTC") marketing standards, and state utility commission rules governing customer solicitations and enrollments, among others. By way of example, telemarketing activity is subject to federal and state do-not-call regulation and certain enrollment standards promulgated by state regulators. Door-to-door sales are governed by the FTC’s “Cooling Off” Rule as well as state-specific regulation in many jurisdictions. In markets in which we conduct customer credit checks, these checks are subject to the requirements of the Fair Credit Reporting Act. Violations of the rules and regulations governing our marketing and sales activity could impact our license to operate in a particular market, result in suspension or otherwise limit our ability to conduct marketing activity in certain markets, and potentially lead to private actions against us. Moreover, there is potential for changes to legislation and regulatory measures applicable to our marketing measures that may impact our business models.

Recent interpretations of the Telephone Consumer Protection Act of 1991 (the “TCPA”) by the Federal Communications Commission (“FCC”) have introduced confusion regarding what constitutes an “autodialer” for purposes of determining compliance under the TCPA. Also, additional restrictions have been placed on wireless telephone numbers making compliance with the TCPA more costly. See “Risk Factors—Risks Related to Our Business and Our Industry—Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply.”

As compliance with the federal TCPA regulations and state telemarketing regulations becomes increasingly costly and as door-to-door marketing becomes increasingly risky both from a regulatory compliance perspective, and from the risk of such activities drawing class action litigation claims, we and our peers who rely on these sales channels will find it more difficult than in the past to engage in direct marketing efforts. In response to these risks, we are experimenting with new technologies, such as a web-based application to process door-to-door sales enrollments with direct input by the consumer. This application can be accessed using tablets or any smart phone device, which enhances and expands the opportunities to market directly to customers.

Our participation in natural gas and electricity wholesale markets to procure supply for our retail customers and hedge pricing risk is subject to regulation by the Commodity Futures Trading Commission (the "CFTC"), including regulation pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act. In order to sell electricity, capacity and ancillary services in the wholesale electricity markets, we are required to have market-based rate authorization, also known as “MBR Authorization,” from the Federal Energy Regulatory Commission ("FERC"). We are required to make status update filings to FERC to disclose any affiliate relationships and quarterly filings to FERC regarding volumes of wholesale electricity sales in order to maintain our MBR Authorization. We are also required to seek prior approval by FERC to the extent any direct or indirect change in control occurs with respect to entities that hold MBR Authorization.

The transportation and sale for resale of natural gas in interstate commerce are regulated by agencies of the U.S. federal government, primarily FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects our ability to procure natural gas supply for our retail customers and hedge pricing risk. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC’s orders do not attempt to directly regulate natural gas retail

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sales. As a shipper of natural gas on interstate pipelines, we are subject to those interstate pipelines' tariff requirements and FERC regulations and policies applicable to shippers.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas marketers and local regulated utilities with which we compete.

In December 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting. As a wholesale buyer and seller of natural gas, we are subject to the reporting requirements of Order 704.

Employees

We employed 164 people as of December 31, 2019, none of which were subject to any collective bargaining agreements. We have not experienced any strikes or work stoppages and consider our relations with our employees to be satisfactory. We also utilize the services of independent contractors and vendors to perform various services.

Facilities

Our corporate headquarters is located in Houston, Texas, and we also maintain an office in Orangeburg, New York.

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Available Information

Our website is located at www.sparkenergy.com. We make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), including our annual reports on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and all amendments to those reports, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Any materials filed with the SEC may be read and copied at the SEC’s website at www.sec.gov.

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Item 1A. Risk Factors

You should carefully consider the risks described below together with the other information contained in this Annual Report on Form 10-K. If any of the risks below were to occur, our business, financial condition, cash flows, results of operation and ability to pay dividends on our Class A common stock and Series A Preferred Stock could be adversely impacted, and the price of the Class A common stock and Series A Preferred Stock could decline and you could lose your investment.

Risks Related to Our Business and Our Industry

We are subject to commodity price risk.

Our financial results are largely dependent on the prices at which we can acquire the commodities we resell. The prevailing market prices for natural gas and electricity have historically, and may continue to fluctuate substantially over relatively short periods of time. Changes in market prices for natural gas and electricity may result from many factors that are outside of our control, including:

—	weather conditions;

—	seasonality;

—	demand for energy commodities and general economic conditions;

—	disruption of natural gas or electricity transmission or transportation infrastructure or other constraints or inefficiencies;

—	reduction or unavailability of generating capacity, including temporary outages, mothballing, or retirements;

—	the level of prices and availability of natural gas and competing energy sources, including the impact of changes in environmental regulations impacting suppliers;

—	the creditworthiness or bankruptcy or other financial distress of market participants;

—	changes in market liquidity;

—	natural disasters, wars, embargoes, acts of terrorism and other catastrophic events;

—	significant changes in the pricing methods in the wholesale markets in which we operate;

—	changes in regulatory policies concerning how markets are structured, how compensation is provided for service, and the kinds of different services that can or must be offered;

—	federal, state, foreign and other governmental regulation and legislation; and

—	demand side management, conservation, alternative or renewable energy sources.

We may not be able to pass along changes to the prices we pay to acquire commodities to our customers and such pricing fluctuations can attract consumer class actions as well as state and federal regulatory actions.

Our financial results may be adversely impacted by weather conditions.

Weather conditions directly influence the demand for and availability of natural gas and electricity and affect the prices of energy commodities. Generally, on most utility systems, demand for natural gas peaks in the winter and demand for electricity peaks in the summer. Typically, when winters are warmer or summers are cooler, demand for energy is lower than expected, resulting in less natural gas and electricity consumption than forecasted. When demand is below anticipated levels due to weather patterns, we may be forced to sell excess supply at prices below our acquisition cost, which could result in reduced margins or even losses.

Conversely, when winters are colder or summers are warmer, consumption may outpace the volumes of natural gas and electricity against which we have hedged, and we may be unable to meet increased demand with storage or swing supply. In these circumstances, we may experience reduced margins or even losses if we are required to purchase additional supply at higher prices. We may fail to accurately anticipate demand due to fluctuations in weather or to effectively manage our supply in response to a fluctuating commodity price environment.

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Our risk management policies and hedging procedures may not mitigate risk as planned, and we may fail to fully or effectively hedge our commodity supply and price risk.

To provide energy to our customers, we purchase commodities in the wholesale energy markets, which are often highly volatile. Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer contracts. We use both physical and financial products to hedge our exposure. The efficacy of our risk management program may be adversely impacted by unanticipated events and costs that we are not able to effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or availability or cost of, financial instruments that help to hedge commodity price.

We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems around the Chicago metropolitan area, we are exposed to basis risk between the Chicago basis and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the smaller quantities that we require.

Additionally, assumptions that we use in establishing our hedges may reduce the effectiveness of our hedging instruments. Considerations that may affect our hedging policies include, but are not limited to, human error, assumptions about customer attrition, the relationship of prices at different trading or delivery points, assumptions about future weather, and our load forecasting models.

In addition, we incur costs monthly for ancillary charges such as reserves and capacity in the electricity sector by ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines are necessary to protect the integrity of the grid. We attempt to estimate such amounts, but they are difficult to estimate because they are charged in arrears by the ISOs and are subject to fluctuations based on weather and other market conditions. We may be unable to fully pass the higher cost of ancillary reserves and reliability services through to our customers, and increases in the cost of these ancillary reserves and reliability services could negatively impact our results of operations.

Many of the natural gas utilities we serve allocate a share of transportation and storage capacity to us as a part of their competitive market operations. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so. In some regulatory programs or under some contracts, this capacity may be subject to recall by the utilities, which could have the effect of us being required to access the spot market to cover such a recall.

ESCOs face risks due to increased and rapidly changing regulations and increasing monetary fines by the state regulatory agencies.

The retail energy industry is highly regulated. Regulations may be changed or reinterpreted and new laws and regulations applicable to our business could be implemented in the future. To the extent that the competitive restructuring of retail electricity and natural gas markets is reversed, altered or discontinued, such changes could have a detrimental impact on our business and overall financial condition.

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Some states are beginning to increase their regulation of their retail electricity and natural gas markets in an effort to increase consumer disclosures and ensure marketing practices are not misleading to consumers. In addition, the fines against ESCOs that regulators are seeking has increased dramatically in recent years. For example, in 2015 the Connecticut Legislature passed legislation providing that licensed electric suppliers in Connecticut could no longer offer variable rate products as Connecticut regulators believed that a variable rate product was inappropriate for residential consumers.

In addition, in December 2019, the NYPSC issued its retail energy market reset order (the “December 2019 Reset Order”), that ESCOs will be required to comply with commencing early May 2020. The December 2019 Reset Order states that ESCOs can only enroll new residential or small nonresidential customers (mass-market customers) or renew existing mass-market customer contracts for gas and/or electric service only if at least one of the following conditions is met: (1) enrollment includes a guaranteed savings over the utility price, as reconciled on an annual basis; (2) enrollment is for a fixed-rate commodity product that is priced at no more than 5% greater than the trailing 12-month average utility supply rate; (3) enrollment is for a renewably sourced electric commodity product that (a) has a renewable mix that is at least 50% greater than the ESCO’s current Renewable Energy Standard (RES) obligation, (b) the ESCO complies with the RES locational and delivery requirements when procuring Renewable Energy Credits (RECs) or entering into bilateral contracts for renewable commodity supply, and (c) there is transparency of information and disclosures provided to the customer with respect to pricing and commodity sourcing.  In addition, by June 9, 2020, all New York ESCOs are directed to essentially re-apply for licenses to serve customers in New York.

We are evaluating the potential impact of the NYPSC's December 2019 Reset Order and subsequent proceedings on our New York operations while preparing to operate in compliance with any new requirements that may come as a result of any new order promulgated by the NYPSC. Given the uncertainty of the outcome of these matters and the final requirements that may be implemented, we are unable to predict at this time the magnitude of the long-term impact on our operations in New York.

Prior to the December 2019 Reset Order, the NYPSC implemented a low-income order that required ESCOs to return existing low-income customers to utility service and stop enrolling new low-income customers unless customers are enrolled in fixed arrangements with guaranteed savings or with value add inclusions (that were entered into prior to the effective date of the low-income order) or if the ESCO receives a waiver from the NYPSC to provide low-income customers with guaranteed savings. As a result of the low-income order, we have been dropping low-income customers back to the applicable utilities as they have rolled off of their contracts. As of December 31, 2019, remaining low-income customers represent approximately 1.3% of our total RCEs in New York and 0.2% of our RCEs overall. There can be no assurance that the NYPSC or state regulatory agencies to which we are subject will not continue trying to implement restrictive anti-competitive regulations on us.

On October 15, 2018, the Attorney General for the Commonwealth of Massachusetts filed suit against another ESCO and others alleging unfair or deceptive acts or practices in violation of a consumer protections act, breach of the covenant of good faith and fair dealing, and violation of the Massachusetts Telemarketing Solicitation Act. Contemporaneously with the filing of their complaint, the Commonwealth filed for injunctive relief seeking to attach purchase of receivables program revenues owed to the ESCO as possible damages. There can be no assurance that the Commonwealth will not pursue similar claims against other ESCOs.

Recently, certain state commissions have begun efforts to restrict the ability of retail suppliers to “pass through” costs to customers associated with certain changes in law or regulatory requirements. For example, on January 22, 2019, the New Jersey Board of Public Utilities ("NJ BPU") sent a cease and desist letter to third party suppliers ("TPS") in New Jersey instructing that a TPS may not charge a customer rate that is higher than the fixed rate applicable during the period for which that rate was fixed. The letter notified TPS that such increases were prohibited and instructed TPS to refund customers amounts charged in excess of the applicable fixed rate. Parties have challenged the NJ BPU’s letter and it is not clear at this time whether refunds will be required. Similarly, the Connecticut Public Utilities Regulatory Authority ("PURA") recently opened a docket after receiving complaints regarding increases by suppliers to certain fixed-price supplier contracts due to change in law triggers. PURA will consider whether suppliers’ actions constitute unfair and deceptive trade practices or otherwise violate applicable laws. PURA is expected to issue a declaratory ruling following its review. Depending on the outcome of these efforts in New Jersey and Connecticut,

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the Company may be required to assume costs that it otherwise would pass on to customers under its change in law provisions and potentially provide refunds to certain customers.

The retail energy business is subject to a high level of federal, state and local regulations, which are subject to change.

Our costs of doing business may fluctuate based on changing state, federal and local rules and regulations. For example, many electricity markets have rate caps, and changes to these rate caps by regulators can impact future price exposure. Similarly, regulatory changes can result in new fees or charges that may not have been anticipated when existing retail contracts were drafted, which can create financial exposure. Our ability to manage cost increases that result from regulatory changes will depend, in part, on how the “change in law provisions” of our contracts are interpreted and enforced, among other factors.

Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply.

Our outbound telemarketing efforts and use of mobile messaging to communicate with our customers subjects us to regulation under the TCPA. Over the last several years, companies have been subject to significant liabilities as a result of violations of the TCPA, including penalties, fines and damages under class action lawsuits. In addition, the increased use by us and other consumer retailers of mobile messaging to communicate with our customers has created new issues of application of the TCPA to these communications. In 2015, the Federal Communications Commission issued several rulings that made compliance with the TCPA more difficult and costly. Our failure to effectively monitor and comply with our activities that are subject to the TCPA could result in significant penalties and the adverse effects of having to defend and ultimately suffer liability in a class action lawsuit related to such non-compliance.

We are also subject to liability under the TCPA for actions of our third party vendors who are engaging in outbound telemarketing efforts on our behalf. The issue of vicarious liability for the actions of third parties in violation of the TCPA remains unclear and has been the subject of conflicting precedent in the federal appellate courts. There can be no assurance that we may be subject to significant damages as a result of a class action lawsuit for actions of our vendors that we may not be able to control.

We are, and in the future may become, involved in legal and regulatory proceedings and, as a result, may incur substantial costs.

We are subject to lawsuits, claims and regulatory proceeds arising in the ordinary course of our business from time to time, including several purported class action lawsuits involving sales practices, telemarketing and TCPA claims, as well as contract disclosure claims and breach of contract claims. These are in various stages and are subject to substantial uncertainties concerning the outcome.

A negative outcome for any of these matters could result in significant damages. Litigation may also negatively impact us by requiring us to pay substantial settlements, increasing our legal costs, diverting management attention from other business issues or harming our reputation with customers.

For additional information regarding the nature and status of certain proceedings, see Note 14 "Commitments and Contingencies" to the audited consolidated financial statements.

Our business is dependent on retaining licenses in the markets in which we operate.

Our business model is dependent on continuing to be licensed in existing markets. We may have a license revoked or not be granted a renewal of a license, or our license could be adversely conditioned or modified (e.g., by increased bond posting obligations). For example, recently, an ESCO was banned by the Public Utilities Commission of Ohio from operating in Ohio for five years in response to allegations that it has misleading and deceptive marketing practices and charged customers four times the rate as compared to other electricity and gas suppliers.

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We may be subject to risks in connection with acquisitions, which could cause us to fail to realize many of the anticipated benefits of such acquisitions.

We have grown our business in part through strategic acquisition opportunities from third parties and from affiliates of our majority shareholder and may continue to do so in the future. Achieving the anticipated benefits of these transactions depends in part upon our ability to identify accretive acquisition targets, accurately assess the benefits and risks of the acquisition prior to undertaking it, and the ability to integrate the acquired businesses in an efficient and effective manner. When we identify an acquisition candidate, there is a risk that we may be unable to negotiate terms that are beneficial to us. Additionally, even if we identify an accretive acquisition target, the successful acquisition of that business requires estimating anticipated cash flow and accretive value, evaluating potential regulatory challenges, retaining customers and assuming liabilities. The accuracy of these estimates is inherently uncertain and our assumptions may turn out to be incorrect.

Furthermore, when we make an acquisition, we may not be able to accomplish the integration process smoothly or successfully. The difficulties of integrating acquisitions can include, among other things:

–	coordinating geographically separate organizations and addressing possible differences in corporate cultures and management philosophies;

–	dedicating significant management resources to the integration of the acquisition, which may temporarily distract management's attention from the day-to-day business of the combined company;

–	increased liquidity needs to support working capital for the purchase of natural gas and electricity supply to meet our customers’ needs, for the credit requirements of forward physical supply and for generally higher operating expenses;

–	operating in states and markets where we have not previously conducted business;

–	managing different and competing brands and retail strategies in the same markets;

–	coordinating customer information and billing systems and determining how to optimize those systems on a consolidated level;

–	ensuring our hedging strategy adequately covers a customer base that is managed through multiple systems;

–	successfully recognizing expected cost savings and other synergies in overlapping functions; and

–	incurring the responsibility and cost to defend and settle regulatory and litigation matters stemming from the acquired company’s pre-acquisition sales and marketing activities, which may not be covered by indemnification.

In many of our acquisition agreements, we are entitled to indemnification from the counterparty for various matters, including breaches of representations, warranties and covenants, tax matters, and litigation proceedings. We generally obtain security to provide assurances that the counterparty could perform its indemnification obligations, which may be in the form of escrow accounts, payment withholding or other methods. However, to the extent that we do not obtain security, or the security turns out to be inadequate, there is a risk that the counterparty may fail to perform on its indemnification obligations, which could result in the losses being incurred by us.

Our ability to grow at levels experienced historically may be constrained if the market for acquisition candidates is limited and we are unable to make acquisitions of portfolios of customers and retail energy companies on commercially reasonable terms.

Pursuant to our cash dividend policy, we distribute a significant portion of our cash through regular quarterly dividends, and our ability to grow and make acquisitions with cash on hand could be limited.

Pursuant to our cash dividend policy, we have historically distributed and intend in the future to distribute, a significant portion of our cash through regular quarterly dividends to holders of our Class A common stock and dividends on our Series A Preferred Stock. As such, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations, and we may have to rely upon external financing sources, including the issuance of debt, equity securities, convertible subordinated notes and borrowings under our Senior

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Credit Facility and Subordinated Facility. These sources may not be available, and our ability to grow and maintain our business may be limited.

We may not be able to manage our growth successfully.

The growth of our operations will depend upon our ability to expand our customer base in our existing markets and to enter new markets in a timely manner at reasonable costs, organically or through acquisitions. In order for us to recover expenses incurred in entering new markets and obtaining new customers, we must attract and retain customers on economic terms and for extended periods. We may experience difficulty managing our growth and implementing new product offerings, integrating new customers and employees, and complying with applicable market rules and the infrastructure for product delivery.

Expanding our operations also may require continued development of our operating and financial controls and may place additional stress on our management and operational resources. We may be unable to manage our growth and development successfully.

Our financial results fluctuate on a seasonal, quarterly and annual basis.

Our overall operating results fluctuate substantially on a seasonal, quarterly and annual basis depending on: (1) the geographic mix of our customer base; (2) the relative concentration of our commodity mix; (3) weather conditions, which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and (4) variability in market prices for natural gas and electricity. These factors can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle. In addition, our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable to those supplies. This timing difference could affect our cash flows, especially during peak cycles in the winter and summer months. Furthermore, as a result of the seasonality of our business, we may reserve a portion of our excess cash available for distribution in the first and fourth quarters in order to fund our second and third quarter distributions.

Additionally, we enter into a variety of financial derivative and physical contracts to manage commodity price risk, and we use mark-to-market accounting to account for this hedging activity. Under the mark-to-market accounting method, changes in the fair value of our hedging instruments that are not qualifying or not designated as hedges under accounting rules are recognized immediately in earnings. As a result of this accounting treatment, changes in the forward prices of natural gas and electricity cause volatility in our quarterly and annual earnings, which we are unable to fully anticipate.

We could also incur volatility from quarter to quarter associated with gains and losses on settled hedges relating to natural gas held in inventory if we choose to hedge the summer-winter spread on our retail allocated storage capacity. We typically purchase natural gas inventory and store it from April to October for withdrawal from November through March. Since a portion of the inventory is used to satisfy delivery obligations to our fixed-price customers over the winter months, we hedge the associated price risk using derivative contracts. Any gains or losses associated with settled derivative contracts are reflected in the statement of operations as a component of retail cost of sales and net asset optimization.

We may have difficulty retaining our existing customers or obtaining a sufficient number of new customers, due to competition and for other reasons.

The markets in which we compete are highly competitive, and we may face difficulty retaining our existing customers or obtaining new customers due to competition. We encounter significant competition from local regulated utilities or their retail affiliates and traditional and new retail energy providers. Many of these competitors

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or potential competitors are larger than us, have access to more significant capital resources, have more well-established brand names and have larger existing installed customer bases.

Additionally, existing customers may switch to other retail energy service providers during their contract terms in the event of a significant decrease in the retail price of natural gas or electricity in order to obtain more favorable prices. Although we generally have a right to collect a termination fee from each customer on a fixed-price contract who terminates their contract early, we may not be able to collect the termination fees in full or at all. Our variable-price contracts can typically be terminated by our customers at any time without penalty. We may be unable to obtain new customers or maintain our existing customers due to competition or otherwise.

Increased collateral requirements in connection with our supply activities may restrict our liquidity.

Our contractual agreements with certain local regulated utilities and our supplier counterparties require us to maintain restricted cash balances or letters of credit as collateral for credit risk or the performance risk associated with the future delivery of natural gas or electricity. These collateral requirements may increase as we grow our customer base. Collateral requirements will increase based on the volume or cost of the commodity we purchase in any given month and the amount of capacity or service contracted for with the local regulated utility. Significant changes in market prices also can result in fluctuations in the collateral that local regulated utilities or suppliers require.

The effectiveness of our operations and future growth depend in part on the amount of cash and letters of credit available to enter into or maintain these contracts. The cost of these arrangements may be affected by changes in credit markets, such as interest rate spreads in the cost of financing between different levels of credit ratings. These liquidity requirements may be greater than we anticipate or are able to meet.

We are subject to direct credit risk for certain customers who may fail to pay their bills as they become due.

We bear direct credit risk related to customers located in markets that have not implemented POR programs as well as indirect credit risk in those POR markets that pass collection efforts along to us after a specified non-payment period. For the year ended December 31, 2019, customers in non-POR markets represented approximately 33% of our retail revenues. We generally have the ability to terminate contracts with customers in the event of non-payment, but in most states in which we operate we cannot disconnect their natural gas or electricity service. In POR markets where the local regulated utility has the ability to return non-paying customers to us after specified periods, we may realize a loss for one to two billing periods until we can terminate these customers’ contracts. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract and we also remain liable to our suppliers of natural gas and electricity for the cost of our supply commodities. Furthermore, in the Texas market, we are responsible for billing the distribution charges for the local regulated utility and are at risk for these charges, in addition to the cost of the commodity, in the event customers fail to pay their bills. Changing economic factors, such as rising unemployment rates and energy prices also result in a higher risk of customers being unable to pay their bills when due.

We depend on the accuracy of data in our information management systems, which subjects us to risks.

We depend on the accuracy and timeliness of our information management systems for billing, collections, consumption and other important data. We rely on many internal and external sources for this information, including:

—	our marketing, pricing and customer operations functions; and

—	various local regulated utilities and ISOs for volume or meter read information, certain billing rates and billing types (e.g., budget billing) and other fees and expenses.

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Inaccurate or untimely information, which may be outside of our direct control, could result in:

—	inaccurate and/or untimely bills sent to customers;

—	incorrect tax remittances;

—	reduced effectiveness and efficiency of our operations;

—	inability to adequately hedge our portfolio;

—	increased overhead costs;

—	inaccurate accounting and reporting of customer revenues, gross margin and accounts receivable activity;

—	inaccurate measurement of usage rates, throughput and imbalances;

—	customer complaints; and

—	increased regulatory scrutiny.

We are also subject to disruptions in our information management systems arising out of events beyond our control, such as natural disasters, pandemics, epidemics, failures in hardware or software, power fluctuations, telecommunications and other similar disruptions. In addition, our information management systems may be vulnerable to computer viruses, incursions by intruders or hackers and cyber terrorists and other similar disruptions. A cyber-attack on our information management systems could severely disrupt business operations, preventing us from billing and collecting revenues, and could result in significant expenses to investigate and repair security breaches or system damage, lead to litigation, fines, other remedial action, heightened regulatory scrutiny, diminished customer confidence and damage to our reputation. Although we maintain cyber-liability insurance that covers certain damage caused by cyber events, it may not be sufficient to cover us in all circumstances.

Our success depends on key members of our management, the loss of whom could disrupt our business operations.

We depend on the continued employment and performance of key management personnel. A number of our senior executives have substantial experience in consumer and energy markets that have undergone regulatory restructuring and have extensive risk management and hedging expertise. We believe their experience is important to our continued success. We do not maintain key life insurance policies for our executive officers. Our key executives may not continue in their present roles and may not be adequately replaced.

We rely on third party vendors for our customer billing and transactions platform that exposes us to third party performance risk.

We have outsourced our back office customer billing and transactions platforms to third party vendors, and we rely heavily on the continued performance of the vendors under our current outsourcing agreement. Our vendors may fail to operate in accordance with the terms of the outsourcing agreement or a bankruptcy or other event may prevent it from performing under our outsourcing agreement.

A large portion of our current customers are concentrated in a limited number of states, making us vulnerable to customer concentration risks.

As of December 31, 2019, approximately 59% of our RCEs were located in five states. Specifically, 16%, 12%, 12%, 10% and 9% of our customers on an RCE basis were located in NY, MA, PA, CT and TX, respectively. If we are unable to increase our market share across other competitive markets or enter into new competitive markets effectively, we may be subject to continued or greater customer concentration risk. The states that contain a large percentage of our customers could reverse regulatory restructuring or change the regulatory environment in a manner that causes us to be unable to operate economically in that state.

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Increases in state renewable portfolio standards or an increase in the cost of renewable energy credit and carbon offsets may adversely impact the price, availability and marketability of our products.

Pursuant to state renewable portfolio standards, we must purchase a specified amount of RECs based on the amount of electricity we sell in a state in a year. In addition, we have contracts with certain customers that require us to purchase RECs or carbon offsets. If a state increases its renewable portfolio standards, the demand for RECs within that state will increase and therefore the market price for RECs could increase. We attempt to forecast the price for the required RECs and carbon offsets at the end of each month and incorporate this forecast into our customer pricing models, but the price paid for RECs and carbon offsets may be higher than forecasted. We may be unable to fully pass the higher cost of RECs through to our customers, and increases in the price of RECs may decrease our results of operations and affect our ability to compete with other energy retailers that have not contracted with customers to purchase RECs or carbon offsets. Further, a price increase for RECs or carbon offsets may require us to decrease the renewable portion of our energy products, which may result in a loss of customers. A further reduction in benefits received by local regulated utilities from production tax credits in respect of renewable energy may adversely impact the availability to us, and marketability by us, of renewable energy under our brands.

Our access to marketing channels may be contingent upon the viability of our telemarketing and door-to-door agreements with our vendors.

Our vendors are essential to our telemarketing and door-to-door sales activities. Our ability to increase revenues in the future will depend significantly on our access to high quality vendors. If we are unable to attract new vendors and retain existing vendors to achieve our marketing targets, our growth may be materially reduced. There can be no assurance that competitive conditions will allow these vendors and their independent contractors to continue to successfully sign up new customers. Further, if our products are not attractive to, or do not generate sufficient revenue for our vendors, we may lose our existing relationships. In addition, the decline in landlines reduces the number of potential customers that may be reached by our telemarketing efforts and as a result our telemarketing sales channel may become less viable and we may be required to use more door-to-door marketing. Door-to-door marketing is continually under scrutiny by state regulators and legislators, which may lead to new rules and regulations that impact our ability to use these channels.

Our vendors may expose us to risks.

We are subject to reputational risks that may arise from the actions of our vendors and their independent contractors that are wholly or partially beyond our control, such as violations of our marketing policies and procedures as well as any failure to comply with applicable laws and regulations. If our vendors engage in marketing practices that are not in compliance with local laws and regulations, we may be in breach of applicable laws and regulations that may result in regulatory proceedings, disadvantageous conditioning of our energy retailer license, or the revocation of our energy retailer license. Unauthorized activities in connection with sales efforts by agents of our vendors, including calling consumers in violation of the TCPA and predatory door-to-door sales tactics and fraudulent misrepresentation could subject us to class action lawsuits against which we will be required to defend. Such defense efforts will be costly and time consuming. In addition, the independent contractors of our vendors may consider us to be their employer and seek compensation.

Risks Related to Our Capital Structure and Capital Stock

Our indebtedness could adversely affect our ability to raise additional capital to fund our operations or pay dividends. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry as well as impact our cash available for distribution.

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We have $123.0 million of indebtedness outstanding and $37.4 million in issued letters of credit under our Senior Credit Facility, and zero of indebtedness outstanding under our Subordinated Facility as of December 31, 2019. Debt we incur under our Senior Credit Facility, Subordinated Facility or otherwise could have negative consequences, including:

—	increasing our vulnerability to general economic and industry conditions;

—	requiring cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing or eliminating our ability to pay dividends to holders of our Class A common stock and Series A Preferred Stock, or to use our cash flow to fund our operations, capital expenditures and future business opportunities;

—	limiting our ability to fund future acquisitions or engage in other activities that we view as in our long-term best interest;

—	restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants, including requirements to maintain certain financial ratios, in our credit facilities and other financing agreements;

—	exposing us to the risk of increased interest rates because certain of our borrowings are at variable rates of interest; and

—	limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes.

If we are unable to satisfy financial covenants in our debt instruments, it could result in an event of default that, if not cured or waived, may entitle the lenders to demand repayment or enforce their security interests. Our Senior Credit Facility will mature in May 2021, and we cannot assure that we will be able to negotiate a new credit arrangement on commercially reasonable terms.

We cannot assure you that we will be able to continue paying our targeted quarterly dividend to the holders of our Class A common stock or dividends to the holders of our Series A Preferred Stock in the future.

The amount of our cash available for distribution principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:

—	changes in commodity prices, which may be driven by a variety of factors, including, but not limited to, weather conditions, seasonality and demand for energy commodities and general economic conditions;

—	the level and timing of customer acquisition costs we incur;

—	the level of our operating and general and administrative expenses;

—	seasonal variations in revenues generated by our business;

—	our debt service requirements and other liabilities;

—	fluctuations in our working capital needs;

—	our ability to borrow funds and access capital markets;

—	restrictions contained in our debt agreements (including our Senior Credit Facility);

—	management of customer credit risk;

—	abrupt changes in regulatory policies; and,

—	other business risks affecting our cash flows.

As a result of these and other factors, we cannot guarantee that we will have sufficient cash generated from operations to pay the dividends on our Series A Preferred Stock or to pay a specific level of cash dividends to holders of our Class A common stock.

The amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of profitability, which is affected by non-cash items. We may incur other expenses or liabilities during a period that could significantly reduce or eliminate our cash available for distribution and, in turn, impair our ability to pay

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dividends to holders of our Class A common stock and Series A Preferred Stock during the period. Additionally, the dividends paid on Series A Preferred Stock reduce the amount of cash we have available to pay dividends on our Class A common stock.

Each new share of Class A common stock and Series A Preferred Stock issued increases the cash required to continue to pay cash dividends. Any Class A common stock or preferred stock (whether Series A Preferred Stock or a new series of preferred stock) that may in the future be issued to finance acquisitions, upon exercise of stock options or otherwise, would have a similar effect.

Finally, dividends to holders of our Class A common stock are paid at the discretion of our board of directors. Our board of directors may decrease the level of or entirely discontinue payment of dividends.

We could be prevented from paying cash dividends on the Class A common stock and Series A Preferred Stock.

Holders of shares of Class A common stock and Series A Preferred Stock do not have a right to dividends on such shares unless declared or set aside for payment by our board of directors. Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay cash dividends on the Class A common stock and Series A Preferred Stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital. Our business may not generate sufficient cash flow from operations to enable us to pay dividends on the Series A Preferred Stock when payable, and quarterly dividends on the Class A common stock. Further, even if adequate surplus is available to pay cash dividends on the Class A common stock and Series A Preferred Stock, we may not have sufficient cash to pay dividends on the Class A common stock or Series A Preferred Stock.

Furthermore, no dividends on Class A common stock or Series A Preferred Stock shall be authorized by our board of directors or paid, declared or set aside for payment by us at any time when the authorization, payment, declaration or setting aside for payment would be unlawful under Delaware law or any other applicable law, or when the terms and provisions of any documents limiting the payment of dividends prohibit the authorization, payment, declaration or setting aside for payment thereof or would constitute a breach or a default under such document.

We are a holding company. Our sole material asset is our equity interest in Spark HoldCo, LLC ("Spark HoldCo") and we are accordingly dependent upon distributions from Spark HoldCo to pay dividends on the Class A common stock and Series A Preferred Stock.

We are a holding company and have no material assets other than our equity interest in Spark HoldCo, and have no independent means of generating revenue. Spark HoldCo or its subsidiaries may be restricted from making distributions to us under applicable law or regulation or under the terms of their financing arrangements, or may otherwise be unable to provide such funds.

The Class A common stock and Series A Preferred Stock are subordinated to our existing and future debt obligations.

The Class A common stock and Series A Preferred Stock are subordinated to all of our existing and future indebtedness (including indebtedness outstanding under the Senior Credit Facility). Therefore, if we become bankrupt, liquidate our assets, reorganize or enter into certain other transactions, assets will be available to pay our obligations with respect to the Series A Preferred Stock only after we have paid all of our existing and future indebtedness in full. The Class A common stock will only receive assets to the extent all existing and future indebtedness and obligations under the Series A Preferred Stock is paid in full. If any of these events were to occur, there may be insufficient assets remaining to make any payments to holders of the Series A Preferred Stock or Class A common stock.

Additionally, none of our subsidiaries have guaranteed or otherwise become obligated with respect to the Class A common stock or Series A Preferred Stock. As a result, the Class A common stock and Series A Preferred Stock

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effectively rank junior to all existing and future indebtedness and other liabilities of our subsidiaries, including our operating subsidiaries, and any capital stock of our subsidiaries not held by us. Accordingly, our right to receive assets from any of our subsidiaries upon our bankruptcy, liquidation or reorganization, and the right of holders of shares of Class A common stock and Series A Preferred Stock to participate in those assets, is also structurally subordinated to claims of that subsidiary’s creditors, including trade creditors. Even if we were a creditor of any of our subsidiaries, our rights as a creditor would be subordinate to any security interest in the assets of that subsidiary and any indebtedness of that subsidiary senior to that held by us.

Numerous factors may affect the trading price of the Class A common stock and Series A Preferred Stock.

The trading price of the Class A common stock and Series A Preferred Stock may depend on many factors, some of which are beyond our control, including:

—	prevailing interest rates;

—	the market for similar securities;

—	general economic and financial market conditions;

—	our issuance of debt or other preferred equity securities; and

—	our financial condition, results of operations and prospects.

One of the factors that will influence the price of the Class A common stock and Series A Preferred Stock will be the distribution yield of the securities (as a percentage of the then market price of the securities) relative to market interest rates. Increases in market interest rates, which have been at low levels relative to historical rates, may lead prospective purchasers of shares of Class A common stock or Series A Preferred Stock to expect a higher distribution yield, and cause them to sell their Class A common stock or Series A Preferred Stock. Accordingly, higher market interest rates could cause the market price of the Class A common stock and Series A Preferred Stock to decrease.

In addition, over the last several years, prices of equity securities in the U.S. trading markets have been experiencing extreme price fluctuations. As a result of these and other factors, investors holding our Class A common stock and Series A Preferred Stock may experience a decrease in the value of their securities, which could be substantial and rapid, and could be unrelated to our financial condition, performance or prospects.

There may not be an active trading market for the Class A common stock or Series A Preferred Stock, which may in turn reduce the market value and your ability to transfer or sell your shares of Class A common stock or Series A Preferred Stock.

There are no assurances that there will be an active trading market for our Class A common stock or Series A Preferred Stock. The liquidity of any market for the Class A common stock and Series A Preferred Stock depends upon the number of stockholders, our results of operations and financial condition, the market for similar securities, the interest of securities dealers in making a market in the Class A common stock and Series A Preferred Stock, and other factors. To the extent that an active trading market is not maintained, the liquidity and trading prices for the Class A common stock and Series A Preferred Stock may be harmed.

Furthermore, because the Series A Preferred Stock does not have any stated maturity and is not subject to any sinking fund or mandatory redemption, stockholders seeking liquidity will be limited to selling their respective shares of Series A Preferred Stock in the secondary market. Active trading markets for the Series A Preferred Stock may not exist at such times, in which case the trading price of your shares of our Series A Preferred Stock could be reduced and your ability to transfer such shares could be limited.

Our Founder holds a substantial majority of the voting power of our common stock.

Holders of Class A and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our certificate of

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incorporation and bylaws. Our Founder controls 66.3% of the combined voting power of the Class A and Class B common stock as of December 31, 2019 through his direct and indirect ownership in us.

Affiliated owners are entitled to act separately with respect to their investment in us, and they have the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, affiliates are able to determine the outcome of all matters requiring Class A common stock and Class B common stock shareholder approval, including mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company. The existence of a significant shareholder, such as our Founder, may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.

So long as affiliates continue to control a significant amount of our common stock, they will continue to be able to strongly influence all matters requiring shareholder approval, regardless of whether other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of affiliates may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A common stock or Series A Preferred Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.

Holders of Series A Preferred Stock have extremely limited voting rights.

Voting rights of holders of shares of Series A Preferred Stock are extremely limited. Our Class A common stock and our Class B common stock are the only classes of our securities carrying full voting rights. Holders of the Series A Preferred Stock generally have no voting rights.

We have engaged in transactions with our affiliates in the past and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. We have acquired companies and books of customers from our affiliates and may do so in the future. We will continue to enter into back-to-back transactions for purchases of commodities and derivatives on behalf of our affiliate. We will also continue to pay certain expenses on behalf of several of our affiliates for which we will seek reimbursement. We will also continue to share our corporate headquarters with certain affiliates. We cannot assure that our affiliates will reimburse us for the costs we have incurred on their behalf or perform their obligations under any of these contracts.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without shareholder approval. On September 20, 2019, we filed a registration statement under the Securities Act on Form S-3 allowing us to offer and sell, from time to time, shares of preferred stock. The registration statement was declared effective on October 18, 2019. The election by our board of directors to issue preferred stock with anti-takeover provisions could make it more difficult for a third party to acquire us.

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In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:

—

provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms. Our staggered board may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for shareholders to replace a majority of the directors;

—	provide that the authorized number of directors may be changed only by resolution of the board of directors;

—	provide that all vacancies in our board, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

—

provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without shareholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

—

provide that at any time after the first date upon which W. Keith Maxwell III no longer beneficially owns more than fifty percent of the outstanding Class A common stock and Class B common stock, any action required or permitted to be taken by the shareholders must be effected at a duly called annual or special meeting of shareholders and may not be effected by any consent in writing in lieu of a meeting of such shareholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of the outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting);

—

provide that at any time after the first date upon which W. Keith Maxwell III no longer beneficially owns more than fifty percent of the outstanding Class A common stock and Class B common stock, special meetings of our shareholders may only be called by the board of directors, the chief executive officer or the chairman of the board (prior to such time, special meetings may also be called by our Secretary at the request of holders of record of fifty percent of the outstanding Class A common stock and Class B common stock);

—	provide that our amended and restated certificate of incorporation and amended and restated bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our outstanding stock entitled to vote thereon;

—	provide that our amended and restated bylaws can be amended by the board of directors; and

—

establish advance notice procedures with regard to shareholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our shareholders. These procedures provide that notice of shareholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. These requirements may preclude shareholders from bringing matters before the shareholders at an annual or special meeting.

In addition, in our amended and restated certificate of incorporation, we have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”) regulating corporate takeovers until the date on which W. Keith Maxwell III no longer beneficially owns in the aggregate more than fifteen percent of the outstanding Class A common stock and Class B common stock. On and after such date, we will be subject to the provisions of Section 203 of the DGCL.

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our

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stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. This exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.

Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Future sales of our Class A common stock and Series A Preferred Stock in the public market could reduce the price of the Class A common stock and Series A Preferred Stock, and may dilute your ownership in us.

On September 20, 2019, we filed a registration statement under the Securities Act on Form S-3 registering the primary offer and sale, from time to time, of Class A common stock, preferred stock, depositary shares and warrants. The registration statement also registers the Class A common stock held by our affiliates, Retailco and NuDevco (including Class A common stock that may be obtained upon conversion of Class B common stock). All of the shares of Class A common stock held by Retailco and NuDevco and registered on the registration statement may be immediately resold. The registration statement was declared effective on October 18, 2019.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances or sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

We may also in the future sell additional shares of preferred stock, including shares of Series A Preferred Stock, on terms that may differ from those we have previously issued. Such shares could rank on parity with or, subject to the voting rights referred to above (with respect to issuances of new series of preferred stock), senior to the Series A Preferred Stock as to distribution rights or rights upon liquidation, winding up or dissolution. The subsequent issuance of additional shares of Series A Preferred Stock, or the creation and subsequent issuance of additional classes of preferred stock on parity with the Series A Preferred Stock, could dilute the interests of the holders of Series A Preferred Stock, and could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock. Any issuance of preferred stock that is senior to the Series A Preferred

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Stock would not only dilute the interests of the holders of Series A Preferred Stock, but also could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock.

Furthermore, subject to compliance with the Securities Act or exemptions therefrom, employees who have received Class A common stock as equity awards may also sell their shares into the public market.

We have issued preferred stock and may continue to do so, and the terms of such preferred stock could adversely affect the voting power or value of our Class A common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock with respect to dividends and distributions, as our board of directors may determine. Through December 31, 2019, we have issued an aggregate of 3,707,256 shares of Series A Preferred Stock.

The terms of the preferred stock we offer or sell could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock, such as the Series A Preferred Stock, could affect the residual value of the Class A common stock.

Our amended and restated certificate of incorporation limits the fiduciary duties of one of our directors and certain of our affiliates and restricts the remedies available to our stockholders for actions taken by our Founder or certain of our affiliates that might otherwise constitute breaches of fiduciary duty.

Our amended and restated certificate of incorporation contains provisions that we renounce any interest in existing and future investments in other entities by, or the business opportunities of, NuDevco Partners, LLC, NuDevco Partners Holdings, LLC and W. Keith Maxwell III, or any of their officers, directors, agents, shareholders, members, affiliates and subsidiaries (other than a director or officer who is presented an opportunity solely in his capacity as a director or officer). Because of this provision, these persons and entities have no obligation to offer us those investments or opportunities that are offered to them in any capacity other than solely as an officer or director. If one of these persons or entities pursues a business opportunity instead of presenting the opportunity to us, we will not have any recourse against such person or entity for a breach of fiduciary duty.

The Series A Preferred Stock represent perpetual equity interests in us, and investors should not expect us to redeem the Series A Preferred Stock on the date the Series A Preferred Stock becomes redeemable by us or on any particular date afterwards.

The Series A Preferred Stock represents a perpetual equity interest in us, and the securities have no maturity or mandatory redemption date and are not redeemable at the option of investors under any circumstances. As a result, unlike our indebtedness, the Series A Preferred Stock will not give rise to a claim for payment of a principal amount at a particular date. As a result, holders of the Series A Preferred Stock may be required to bear the financial risks of an investment in the Series A Preferred Stock for an indefinite period of time. In addition, the Series A Preferred Stock will rank junior to all our current and future indebtedness (including indebtedness outstanding under the Senior Credit Facility) and other liabilities. The Series A Preferred Stock will also rank junior to any other preferred stock ranking senior to the Series A Preferred Stock we may issue in the future with respect to assets available to satisfy claims against us.

The Series A Preferred Stock is not rated.

We have not sought to obtain a rating for the Series A Preferred Stock, and the Series A Preferred Stock may never be rated. It is possible, however, that one or more rating agencies might independently determine to assign a rating to the Series A Preferred Stock or that we may elect to obtain a rating of the Series A Preferred Stock in the future. In addition, we may elect to issue other securities for which we may seek to obtain a rating. If any ratings are

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assigned to the Series A Preferred Stock in the future or if we issue other securities with a rating, such ratings, if they are lower than market expectations or are subsequently lowered or withdrawn, could adversely affect the market for or the market value of the Series A Preferred Stock. Ratings only reflect the views of the issuing rating agency or agencies and such ratings could at any time be revised downward or withdrawn entirely at the discretion of the issuing rating agency. A rating is not a recommendation to purchase, sell or hold any particular security, including the Series A Preferred Stock. Ratings do not reflect market prices or suitability of a security for a particular investor and any future rating of the Series A Preferred Stock may not reflect all risks related to us and our business, or the structure or market value of the Series A Preferred Stock.

We cannot guarantee that our Repurchase Program will enhance shareholder value and purchases, if any, could increase the volatility of the price of our Series A Preferred Stock.

Our Board of Directors has authorized the Repurchase Program, which permits us to purchase our Series A Preferred Stock through December 31, 2020. The Repurchase Program does not obligate us to purchase a specific dollar amount or number of shares of Series A Preferred Stock. The specific timing and amount of purchases, if any, will depend upon several factors, including ongoing assessments of capital needs, the market price of the Series A Preferred Stock, and other factors, including general market conditions. There can be no assurance that we will make future purchases of Series A Preferred Stock or that we will purchase a sufficient number of shares to satisfy market expectations.

Purchases of our Series A Preferred Stock could affect the market price and increase volatility of our Series A Preferred Stock. We cannot provide any assurance that purchases under the Repurchase Program will be made at the best possible price. Additionally, purchases under our Repurchase Program could diminish our cash reserves or increase borrowings under our Senior Credit Facility or Subordinated Facility, which may impact our ability to finance future growth and to pursue possible future strategic opportunities and acquisitions. Although our Repurchase Program is intended to enhance long-term shareholder value, there is no assurance that it will do so.

We are permitted to and could discontinue our Repurchase Program prior to its expiration or completion. The existence of the Repurchase Program could cause our Series A Preferred Stock price to be higher than it would be in the absence of such a program, and any such discontinuation could cause the market price of our Series A Preferred Stock to decline.

The Change of Control Conversion Right may make it more difficult for a party to acquire us or discourage a party from acquiring us.

The Change of Control Conversion Right of the Series A Preferred Stock provided in the Certificate of Designation may have the effect of discouraging a third party from making an acquisition proposal for us or of delaying, deferring or preventing certain of our change of control transactions under circumstances that otherwise could provide the holders of our Series A Preferred Stock with the opportunity to realize a premium over the then-current market price of such equity securities or that stockholders may otherwise believe is in their best interests.

Changes in the method of determining the London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest rates under our Senior Credit Facility and the floating dividend rate of our Series A Preferred Stock.

LIBOR is a basic rate of interest widely used as a global reference for setting interest rates on loans and payment rates on other financial instruments. Our Senior Credit Facility uses LIBOR as the reference rate for Eurodollar denominated borrowings. In addition, on and after April 15, 2022, dividends on the Series A Preferred Stock accrue at a floating rate equal to the sum of: (a) Three-Month LIBOR Rate as calculated on each applicable determination date, plus (b) 6.578%.

In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if LIBOR will cease to exist at that time, if new methods of calculating LIBOR will be established such that it continues to exist after 2021 or whether different reference rates

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will develop. It is impossible to predict the effect these developments, any discontinuance, modification or other reforms to LIBOR or the establishment of alternative reference rates may have on LIBOR, other benchmark rates or floating rate debt instruments.

Although our Senior Credit Facility and Series A Preferred Stock contain LIBOR alternative provisions and the use of alternative reference rates, new methods of calculating LIBOR or other reforms could cause the interest rates under our Senior Credit Facility or the dividend rate on our Series A Preferred Stock to be materially different than expected, which could have an adverse effect on our business, financial position, and results of operations, and our ability to pay dividends on the Series A Preferred Stock and Class A common stock.

If we are unable to redeem the Series A Preferred Stock on or after April 15, 2022, a substantial increase in the Three-Month LIBOR Rate or an alternative rate could negatively impact our ability to pay dividends on the Series A Preferred Stock and Class A common stock.

If we do not repurchase or redeem our Series A Preferred Stock on or after April 15, 2022, a substantial increase in the Three-Month LIBOR Rate (if it then exists), or a substantial increase in the alternative reference rate, could negatively impact our ability to pay dividends on the Series A Preferred Stock. An increase in the dividends payable on our Series A Preferred Stock would negatively impact dividends on our Class A common stock. We cannot assure you that we will have adequate sources of capital to repurchase or redeem the Series A Preferred Stock on or after April 15, 2022. If we are unable to repurchase or redeem the Series A Preferred Stock and our ability to pay dividends on the Series A Preferred Stock and Class A common stock is negatively impacted, the market value of the Series A Preferred Stock and Class A common stock could be materially adversely impacted.

We may not have sufficient earnings and profits in order for dividends on the Series A Preferred Stock to be treated as dividends for U.S. federal income tax purposes.

The dividends payable by us on the Series A Preferred Stock may exceed our current and accumulated earnings and profits, as calculated for U.S. federal income tax purposes. If this occurs, it will result in the amount of the dividends that exceed such earnings and profits being treated for U.S. federal income tax purposes first as a return of capital to the extent of the beneficial owner’s adjusted tax basis in the Series A Preferred Stock, and the excess, if any, over such adjusted tax basis as gain from the sale or exchange of property, which generally results in capital gain. Such treatment will generally be unfavorable for corporate beneficial owners and may also be unfavorable to certain other beneficial owners.

You may be subject to tax if we make or fail to make certain adjustments to the conversion rate of the Series A Preferred Stock even though you do not receive a corresponding cash dividend.

The Conversion Rate as defined in the Certificate of Designation for the Series A Preferred Stock is subject to adjustment in certain circumstances. A failure to adjust (or to adjust adequately) the Conversion Rate after an event that increases your proportionate interest in us could be treated as a deemed taxable dividend to you. If you are a non-U.S. holder, any deemed dividend may be subject to U.S. federal withholding tax at a 30% rate, or such lower rate as may be specified by an applicable treaty, which may be set off against subsequent payments on the Series A Preferred Stock. In April 2016, the Internal Revenue Service issued new proposed income tax regulations in regard to the taxability of changes in conversion rights that will apply to the Series A Preferred Stock when published in final form and may be applied to us before final publication in certain instances.

We are a “controlled company” under NASDAQ Global Select Market rules, and as such we are entitled to an exemption from certain corporate governance standards of the NASDAQ Global Select Market, and you may not have the same protections afforded to shareholders of companies that are subject to all of the NASDAQ Global Market corporate governance requirements.

We qualify as a “controlled company” within the meaning of NASDAQ Global Select Market corporate governance standards because an affiliated holder controls more than 50% of our voting power. Under NASDAQ Global Select

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Market rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements.

Although our board of directors has established a nominating and corporate governance committee and a compensation committee of independent directors, it may determine to eliminate these committees at any time. If these committees were eliminated, you may not have the same protections afforded to shareholders of companies that are subject to all of NASDAQ Global Select Market corporate governance requirements.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

We are the subject of lawsuits and claims arising in the ordinary course of business from time to time. Management cannot predict the ultimate outcome of such lawsuits and claims. While the lawsuits and claims are asserted for amounts that may be material, should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations except as described in Part II, Item 8 “Financial Statements and Supplementary Data,” Note 14 "Commitments and Contingencies" to the audited consolidated financial statements, which are incorporated herein by reference.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our Class A common stock is traded on the NASDAQ Global Select Market under the symbol “SPKE." There is no public market for our Class B common stock. On March 3, 2020, we had one holder of record of our Class A common stock and two holders of record of our Class B common stock, excluding stockholders for whom shares are held in “nominee” or “street name.”

Dividends

We typically pay a cash dividend each quarter to holders of our Class A common stock to the extent we have cash available for distribution and are permitted to do so under the terms of our Senior Credit Facility.

Recent Sales of Unregistered Equity Securities

We have not sold any unregistered equity securities other than as previously reported.

Purchases of Equity Securities

The following table sets forth information regarding purchases of our Series A Preferred Stock by us during the three months ended December 31, 2019 pursuant to our Repurchase Program.

Period	(a) Total Number of Shares Purchased		(b) Average Price Paid per Share			(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)		(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (1)
October 1 - October 31, 2019	2,300		$	24.94		2,300		—
November 1 - November 30, 2019	23,138		24.82			23,138		—
December 1 - December 31, 2019	—		—			—		—
Total	25,438		$	24.83		25,438		—

(1) On May 22, 2019, the Company announced that the Board of Directors authorized the Repurchase Program to purchase shares of Series A Preferred Stock through May 20, 2020. On November 8, 2019, the Repurchase Program was amended and extended through December 31, 2020. There is no dollar limit on the amount of Series A Preferred Stock that may be purchased. The Repurchase Program does not obligate us to make any repurchases and may be suspended for periods or discontinued at any time.

Stock Performance Graph

The following graph compares the quarterly performance of our Class A common stock to the NASDAQ Composite Index ("NASDAQ Composite") and the Dow Jones U.S. Utilities Index ("IDU"). The chart assumes that the value of the investment in our Class A common stock and each index was $100 at December 31, 2014 and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.

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The performance graph above and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference.

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Item 6. Selected Financial Data

The following table sets forth selected historical financial information for each of the years in the five year period ended December 31, 2019. The information as of and for the years ended December 31, 2019, 2018 and 2017 is derived from the consolidated financial statements contained in this Form 10-K and should be read in conjunction with the information contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data.” Financial information as of and for the years ended December 31, 2016 and 2015 was derived from information filed as part of our 2018 and 2017 Form 10-Ks.

(in thousands, except per share and volumetric data)		Year Ended December 31,
		2019				2018				2017				2016				2015
Income Statement Data:
Total revenues		$	813,725			$	1,005,928			$	798,055			$	546,697			$	358,153
Operating income (loss)		23,979				(3,654		)		102,420				84,001				29,905
Net income (loss)		14,213				(14,392		)		75,044				65,673				25,975
Net income (loss) attributable to Non-Controlling Interests		5,763				(13,206		)		55,799				51,229				22,110
Net income (loss) attributable to Spark Energy, Inc. stockholders		8,450				(1,186		)		19,245				14,444				3,865
Net income (loss) attributable to stockholders of Class A common stock		359				(9,295		)		16,207				14,444				3,865
Net income (loss) attributable to Spark Energy, Inc. per share of Class A common stock
Basic		$	0.03			$	(0.69	)		$	1.23			$	1.27			$	0.63
Diluted		$	0.02			$	(0.69	)		$	1.21			$	1.11			$	0.53
Weighted average common shares outstanding
Basic		14,286				13,390				13,143				11,402				6,129
Diluted		14,568				13,390				13,346				12,690				6,655
Balance Sheet Data:
Current assets		$	236,128			$	291,980			$	296,738			$	197,983			$	102,680
Current liabilities		$	141,955			$	141,951			$	151,027			$	184,056			$	84,188
Total assets		$	422,968			$	488,738			$	503,741			$	367,749			$	162,234
Long-term liabilities		$	123,712			$	165,735			$	152,446			$	67,438			$	44,727
Cash Flow Data:
Cash flows provided by operating activities		$	91,735			$	59,763			$	62,131			$	66,950			$	45,931
Cash flows provided by (used in) investing activities		$	1,398			$	(18,981	)		$	(77,558	)		$	(33,489	)		$	(41,943	)
Cash flows (used in) provided by financing activities		$	(85,103	)		$	(20,563	)		$	25,886			$	(18,975	)		$	(3,873	)
Other Financial Data:
Adjusted EBITDA (1)		$	92,404			$	70,716			$	102,884			$	81,892			$	36,869
Retail gross margin (1)		$	220,740			$	185,109			$	224,509			$	182,369			$	113,615
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders		$	(45,176	)		$	(45,261	)		$	(43,319	)		$	(43,297	)		$	(20,043	)
Other Operating Data:
RCEs (thousands)		672				908				1,042				774				415
Electricity volumes (MWh)		6,416,568				8,630,653				6,755,663				4,170,593				2,075,479
Natural gas volumes (MMBtu)		14,543,563				16,778,393				18,203,684				16,819,713				14,786,681

(1) Adjusted EBITDA and retail gross margin are non-GAAP financial measures. For a definition and reconciliation of each of Adjusted EBITDA and retail gross margin to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Management's Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Performance Measures.”

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the related notes thereto included elsewhere in this Annual Report. In this Annual Report, the terms “Spark Energy,” “Company,” “we,” “us” and “our” refer collectively to Spark Energy, Inc. and its subsidiaries.

Overview

We are an independent retail energy services company founded in 1999 that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure. As of December 31, 2019, we operated in 94 utility service territories across 19 states and the District of Columbia.

Our business consists of two operating segments:

•

Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial transactions with market counterparties and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2019, 2018 and 2017, approximately 85%, 86% and 82%, respectively, of our retail revenues were derived from the sale of electricity.

•

Retail Natural Gas Segment. In this segment, we purchase natural gas supply through physical and financial transactions with market counterparties and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2019, 2018 and 2017, approximately 15%, 14% and 18%, respectively, of our retail revenues were derived from the sale of natural gas.

Recent Developments

Preferred Stock Repurchase Program

In November 2019, we amended and extended our repurchase program (the "Repurchase Program") of our Series A Preferred Stock. The Repurchase Program allows us to purchase Series A Preferred Stock through December 31, 2020, at prevailing prices, in open market or negotiated transactions, subject to market conditions, maximum share prices and other considerations. The Repurchase Program does not obligate us to make any repurchases and may be suspended at any time.

Drivers of Our Business

The success of our business and our profitability are impacted by a number of drivers, the most significant of which are discussed below.

Customer Growth

Customer growth is a key driver of our operations. Our ability to acquire customers organically or by acquisition is important to our success as we experience ongoing customer attrition. Our customer growth strategy includes growing organically through traditional sales channels complemented by customer portfolio and business acquisitions.

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We measure our number of customers using residential customer equivalents ("RCEs"). The following table shows our RCEs by segment as of December 31, 2019, 2018 and 2017:

RCEs:
	December 31,
(In thousands)	2019	2018	2017
Retail Electricity	533	754	868
Retail Natural Gas	139	154	174
Total Retail	672	908	1,042

The following table details our count of RCEs by geographical location as of December 31, 2019:

RCEs by Geographic Location:
(In thousands)	Electricity	% of Total	Natural Gas	% of Total	Total	% of Total
New England	217	41%	27	20%	244	36%
Mid-Atlantic	196	37%	49	35%	245	36%
Midwest	57	10%	42	30%	99	15%
Southwest	63	12%	21	15%	84	13%
Total	533	100%	139	100%	672	100%

The geographical locations noted above include the following states:

•	New England - Connecticut, Maine, Massachusetts and New Hampshire;

•	Mid-Atlantic - Delaware, Maryland (including the District of Columbia), New Jersey, New York and Pennsylvania;

•	Midwest - Illinois, Indiana, Michigan and Ohio; and

•	Southwest - Arizona, California, Colorado, Florida, Nevada and Texas.

Across our market areas, we have operated under a number of different retail brands. We currently operate under seven retail brands. During 2019 and 2018, we consolidated our brands and billings systems in an effort to simplify our business operations. Our goal is to reduce the number of separate brands to three by the end of 2020.

Organic Sales

Our organic sales strategies are designed to offer competitive pricing, price certainty, and/or green product offerings to residential and commercial customers. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices to the price offered by the local regulated utility. We then determine if there is an opportunity in a particular market based on our ability to create a competitive product on economic terms that provides customer value and satisfies our profitability objectives. We develop marketing campaigns using a combination of sales channels. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired targets. During the year ended December 31, 2019, we added approximately 214,000 RCEs through our various organic sales channels.

Acquisitions

We acquire companies and portfolios of customers through both external and affiliated channels. In 2017, we acquired approximately 206,000 RCEs through acquisitions of Verde Energy USA Holdings, LLC ("Verde

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Energy"), Perigee Energy, LLC ("Perigee Energy"), and a customer portfolio. In 2018, we added approximately 81,000 RCEs through our acquisitions of HIKO, a customer portfolio from an affiliate, and a customer portfolio from Starion Energy ("Starion"). In 2019, we added approximately 33,000 RCEs as part of the completion of the acquisition from Starion.

Our ability to realize returns from acquisitions that are acceptable to us is dependent on our ability to successfully identify, negotiate, finance and integrate acquisitions.

RCE Activity

The following table shows our RCE activity during the years ended December 31, 2019, 2018 and 2017.

(In thousands)	Retail Electricity	Retail Natural Gas	Total	% Net Annual Increase (Decrease)
December 31, 2016	571	203	774
Additions	659	61	720
Attrition	(362)	(90)	(452)
December 31, 2017	868	174	1,042	35%
Additions	363	69	432
Attrition	(477)	(89)	(566)
December 31, 2018	754	154	908	(13)%
Additions	189	58	247
Attrition	(410)	(73)	(483)
December 31, 2019	533	139	672	(26)%

The increase of our RCE counts in 2017 was related to the acquisition of customers and businesses in excess of natural customer attrition. In 2018 and 2019, our attrition exceeded customer adds due to our intentional non-renewal of certain larger C&I customer contracts, lower organic sales spending, and fewer acquisitions and slightly higher attrition impacted by our brand consolidation activities. Average monthly attrition rates during 2019, 2018 and 2017 were as follows:

	Year Ended	Quarter Ended
	December 31	December 31	September 30	June 30	March 31
2017	4.3%	4.9%	4.2%	4.1%	3.8%
2018	4.7%	6.7%	4.0%	3.7%	4.2%
2019	5.0%	7.0%	4.0%	3.8%	5.4%

Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves (iii) disconnection resulting from customer payment defaults and (iv) pro-active non-renewal of contracts. Customer attrition during the year ended December 31, 2019 was slightly higher than the prior year due to a previously communicated strategy to shrink our C&I customer book, resulting in our pro-active non-renewal of some of our lower-margin large commercial contracts.

Customer Acquisition Costs

Managing customer acquisition costs is a key component of our profitability. Customer acquisition costs are those costs related to obtaining customers organically and do not include the cost of acquiring customers through acquisitions, which are recorded as customer relationships. For each of the three years ended December 31, 2019, customer acquisition costs were as follows:

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	Year Ended December 31,
(In thousands)	2019			2018			2017
Customer Acquisition Costs	$	18,685		$	13,673		$	25,874

We strive to maintain a disciplined approach to recovery of our customer acquisition costs within a 12 month period. We capitalize and amortize our customer acquisition costs over a two year period, which is based on our estimate of the expected average length of a customer relationship. We factor in the recovery of customer acquisition costs in determining which markets we enter and the pricing of our products in those markets. Accordingly, our results are significantly influenced by our customer acquisition costs. Changes in customer acquisition costs from period to period reflect our focus on growing organically versus growth through acquisitions. We are currently focused on growing through organic sales channels; however, we continue to evaluate opportunities to acquire customers through acquisitions and pursue such acquisitions when it makes sense economically or strategically for the Company.

Customer Credit Risk

Approximately 67% of our revenues are derived from customers in utilities where customer credit risk is borne by the utility in exchange for a discount on amounts billed. Where we have customer credit risk, we record bad debt based on an estimate of uncollectible amounts. Our bad debt expense on non-POR revenues was as follows:

	Year Ended December 31,
	2019		2018		2017
Total Non-POR Bad Debt as Percent of Revenue	3.3	%	2.6	%	2.5	%

During the year ended December 31, 2019, we experienced higher bad debt expense versus 2018 primarily due to an increase in residential customers in non-POR markets. In addition, as our geographic and acquisition channel mix has changed, our bad debt expense has increased. In order to manage this exposure in 2019, we have increased our focus on: collection efforts, timely billing, and credit monitoring for new enrollments in non-POR markets. During the year ended December 31, 2018, we experienced higher bad debt expense versus 2017 primarily as a result of our brand consolidations.

For the years ended December 31, 2019, 2018 and 2017, approximately 67%, 66% and 66%, respectively, of our retail revenues were collected through POR programs where substantially all of our credit risk was with local regulated utility companies. As of December 31, 2019, 2018 and 2017, all of these local regulated utility companies had investment grade ratings. During these same periods, we paid these local regulated utilities a weighted average discount of approximately 0.8%, 1.0% and 1.1%, respectively, of total revenues for customer credit risk protection.

Weather Conditions

Weather conditions directly influence the demand for natural gas and electricity and affect the prices of energy commodities. Our hedging strategy is based on forecasted customer energy usage, which can vary substantially as a result of weather patterns deviating from historical norms. We are particularly sensitive to this variability in our residential customer segment where energy usage is highly sensitive to weather conditions that impact heating and cooling demand.

Our risk management policies direct that we hedge substantially all of our forecasted demand, which is typically hedged to long-term normal weather patterns. We also attempt to add additional protection through hedging from time to time to protect us from potential volatility in markets where we have historically experienced higher exposure to extreme weather conditions. Because we attempt to match commodity purchases to anticipated demand, unanticipated changes in weather patterns can have a significant impact on our operating results and cash flows from period to period.

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We experienced milder than normal weather in most of our geographies for most of 2019 with the exception of the third quarter. This milder weather resulted in lower sales volumes during the period and lower demand for commodities. In markets where we were fully hedged, we were selling back some of those hedges into a depressed wholesale market. During the first quarter of 2019, we experienced weather volatility in the New England, Mid-Atlantic and Midwest regions that resulted in higher-than-normal heating degree days. On average, the first quarter of 2019 turned out to be milder than normal, however prices in the day-ahead and real-time markets during this time were less volatile than they had been in the first quarter of 2018, which in aggregate positively affected our gross margin.

During the third quarter of 2019, we experienced warmer than normal weather across many of our markets, which increased demand for electricity from our customer base. In anticipation of increased demand and volatility in ERCOT ("Electric Reliability Council of Texas"), and as an additional form of insurance, we purchased additional power to mitigate the volatility observed in late August and early September of 2019. These factors had a positive impact on our electricity unit margins in the third quarter of 2019.

Asset Optimization

Our asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is typically at its highest. Given the opportunistic nature of these activities and because we account for these activities using the mark to market method of accounting, we experience variability in our earnings from our asset optimization activities from year to year.

Net asset optimization resulted in a gain of $2.8 million, a gain of $4.5 million and a loss of $0.7 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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Non-GAAP Performance Measures

We use the Non-GAAP performance measures of Adjusted EBITDA and Retail Gross Margin to evaluate and measure our operating results. These measures for the three years ended December 31, 2019 were as follows:

	Year Ended December 31,
(in thousands)	2019				2018				2017
Adjusted EBITDA	$	92,404			$	70,716			$	102,884
Retail Gross Margin	$	220,740			$	185,109			$	224,509

Adjusted EBITDA. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the current period, plus or minus (ii) net gain (loss) on derivative instruments, and (iii) net current period cash settlements on derivative instruments, plus (iv) non-cash compensation expense, and (v) other non-cash and non-recurring operating items. EBITDA is defined as net income (loss) before the provision for income taxes, interest expense and depreciation and amortization.

We deduct all current period customer acquisition costs (representing spending for organic customer acquisitions) in the Adjusted EBITDA calculation because such costs reflect a cash outlay in the period in which they are incurred, even though we capitalize and amortize such costs over two years. We do not deduct the cost of customer acquisitions through acquisitions of businesses or portfolios of customers in calculating Adjusted EBITDA.

We deduct our net gains (losses) on derivative instruments, excluding current period cash settlements, from the Adjusted EBITDA calculation in order to remove the non-cash impact of net gains and losses on these instruments. We also deduct non-cash compensation expense that results from the issuance of restricted stock units under our long-term incentive plan due to the non-cash nature of the expense. Finally, we also adjust from time to time other non-cash or unusual and/or infrequent charges due to either their non-cash nature or their infrequency.

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our liquidity and financial condition and results of operations and that Adjusted EBITDA is also useful to investors as a financial indicator of our ability to incur and service debt, pay dividends and fund capital expenditures. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following:

 

•	our operating performance as compared to other publicly traded companies in the retail energy industry, without regard to financing methods, capital structure or historical cost basis;

•	the ability of our assets to generate earnings sufficient to support our proposed cash dividends;

•	our ability to fund capital expenditures (including customer acquisition costs) and incur and service debt; and

•	our compliance with financial debt covenants. (Refer to Note 10 "Debt" in the Company’s audited consolidated financial statements for discussion of the material terms of our Senior Credit Facility, including the covenant requirements for our Minimum Fixed Charge Coverage Ratio, Maximum Total Leverage Ratio, and Maximum Senior Secured Leverage Ratio.)

The GAAP measures most directly comparable to Adjusted EBITDA are net income (loss) and net cash provided by (used in) operating activities. The following table presents a reconciliation of Adjusted EBITDA to these GAAP measures for each of the periods indicated.

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	Year Ended December 31,
(in thousands)	2019				2018				2017
Reconciliation of Adjusted EBITDA to Net Income (Loss):
Net income (loss)	$	14,213			$	(14,392	)		$	75,044
Depreciation and amortization	40,987				52,658				42,341
Interest expense	8,621				9,410				11,134
Income tax expense	7,257				2,077				38,765
EBITDA	71,078				49,753				167,284
Less:
Net, (Losses) gains on derivative instruments	(67,749		)		(18,170		)		5,008
Net, Cash settlements on derivative instruments	42,820				(10,587		)		16,309
Customer acquisition costs	18,685				13,673				25,874
Plus:
Non-cash compensation expense	5,487				5,879				5,058
Non-recurring legal and regulatory settlements	14,457				—				—
Gain on disposal of eRex	(4,862		)		—				—
Change in Tax Receivable Agreement liability (1)	—				—				(22,267		)
Adjusted EBITDA	$	92,404			$	70,716			$	102,884

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13 "Income Taxes."

The following table presents a reconciliation of Adjusted EBITDA to net cash provided by operating activities for each of the periods indicated.

	Year Ended December 31,
(in thousands)	2019				2018				2017
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	91,735			$	59,763			$	62,131
Amortization of deferred financing costs	(1,275		)		(1,291		)		(1,035		)
Bad debt expense	(13,532		)		(10,135		)		(6,550		)
Interest expense	8,621				9,410				11,134
Income tax expense	7,257				2,077				38,765
Change in Tax Receivable Agreement liability (1)	—				—				(22,267		)
Changes in operating working capital
Accounts receivable, prepaids, current assets	(33,475		)		10,482				31,905
Inventory	(924		)		(674		)		718
Accounts payable and accrued liabilities	11,534				(5,093		)		(13,672		)
Other	22,463				6,177				1,755
Adjusted EBITDA	$	92,404			$	70,716			$	102,884
Cash Flow Data:
Cash flows provided by operating activities	$	91,735			$	59,763			$	62,131
Cash flows provided by (used in) investing activities	$	1,398			$	(18,981	)		$	(77,558	)
Cash flows (used in) provided by financing activities	$	(85,103	)		$	(20,563	)		$	25,886

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13 "Income Taxes."

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Retail Gross Margin. We define retail gross margin as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (iii) net asset optimization revenues (expenses), (iv) net gains (losses) on non-trading derivative instruments, and (v) net current period cash settlements on non-trading derivative instruments. Retail gross margin is included as a supplemental disclosure because it is a primary performance measure used by our management to determine the performance of our retail natural gas and electricity segments. As an indicator of our retail energy business’s operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP.

We believe retail gross margin provides information useful to investors as an indicator of our retail energy business's operating performance.

The GAAP measure most directly comparable to Retail Gross Margin is operating income (loss). The following table presents a reconciliation of Retail Gross Margin to operating income (loss) for each of the periods indicated.

	Year Ended December 31,
(in thousands)	2019				2018				2017
Reconciliation of Retail Gross Margin to Operating Income (Loss):
Operating income (loss)	$	23,979			$	(3,654	)		$	102,420
Plus:
Depreciation and amortization	40,987				52,658				42,341
General and administrative expense	133,534				111,431				101,127
Less:
Net asset optimization revenue (expense)	2,771				4,511				(717		)
(Losses) gains on non-trading derivative instruments	(67,955		)		(19,571		)		5,588
Cash settlements on non-trading derivative instruments	42,944				(9,614		)		16,508
Retail Gross Margin	$	220,740			$	185,109			$	224,509
Retail Gross Margin - Retail Electricity Segment	$	160,540			$	124,668			$	158,468
Retail Gross Margin - Retail Natural Gas Segment	$	60,200			$	60,441			$	66,041

Our non-GAAP financial measures of Adjusted EBITDA and Retail Gross Margin should not be considered as alternatives to net income (loss), net cash provided by operating activities, or operating income (loss). Adjusted EBITDA and Retail Gross Margin are not presentations made in accordance with GAAP and have limitations as analytical tools. You should not consider Adjusted EBITDA or Retail Gross Margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Retail Gross Margin exclude some, but not all, items that affect net income (loss), net cash provided by operating activities, and operating income (loss), and are defined differently by different companies in our industry, our definition of Adjusted EBITDA and Retail Gross Margin may not be comparable to similarly titled measures of other companies.

Management compensates for the limitations of Adjusted EBITDA and Retail Gross Margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

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Consolidated Results of Operations

(In Thousands)	Year Ended December 31,
	2019				2018				2017
Revenues:
Retail revenues	$	810,954			$	1,001,417			$	798,772
Net asset optimization revenues (expenses)	2,771				4,511				(717		)
Total Revenues	813,725				1,005,928				798,055
Operating Expenses:
Retail cost of revenues	615,225				845,493				552,167
General and administrative expense	133,534				111,431				101,127
Depreciation and amortization	40,987				52,658				42,341
Total Operating Expenses	789,746				1,009,582				695,635
Operating income (loss)	23,979				(3,654		)		102,420
Other (expense)/income:
Interest expense	(8,621		)		(9,410		)		(11,134		)
Change in Tax Receivable Agreement liability (1)	—				—				22,267
Gain on disposal of eRex	4,862				—				—
Total other income/(expense)	1,250				749				256
Total other (expenses)/income	(2,509		)		(8,661		)		11,389
Income (loss) before income tax expense	21,470				(12,315		)		113,809
Income tax expense	7,257				2,077				38,765
Net income (loss)	$	14,213			$	(14,392	)		$	75,044
Other Performance Metrics:
Adjusted EBITDA (2)	$	92,404			$	70,716			$	102,884
Retail Gross Margin (2)	220,740				185,109				224,509
Customer Acquisition Costs	18,685				13,673				25,874
RCE Attrition	5.0		%		4.7		%		4.3		%
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders	$	(45,176	)		$	(45,261	)		$	(43,319	)

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13 "Income Taxes."

(2) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See “—Non-GAAP Performance Measures” for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable GAAP financial measures.

Total Revenues. Total revenues for the year ended December 31, 2019 were approximately $813.7 million, a decrease of approximately $192.2 million, or 19%, from approximately $1,005.9 million for the year ended December 31, 2018. This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in 2019 as compared to 2018, partially offset by an increase in electricity unit revenue per MWh. Total revenues for the year ended December 31, 2018 increased approximately $207.8 million, or 26%, from approximately $798.1 million for the year ended December 31, 2017. This increase was primarily due to an increase in electricity volumes driven by the acquisitions of the HIKO and two customer portfolios, full year results from the Verde Companies, and higher-than-normal electricity and natural gas pricing in 2018, partially offset by a decrease in natural gas volumes due to warmer-than-normal weather in the second and third quarters of 2018.

Analysis of the impact of changes in prices and volumes between the years ended December 31, 2019, 2018 and 2017 are as follows:

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	2019 vs. 2018				2018 vs. 2017
Change in electricity volumes sold	$	(221.5	)		$	182.5
Change in natural gas volumes sold	(18.4		)		(11.1		)
Change in electricity unit revenue per MWh	46.5				23.4
Change in natural gas unit revenue per MMBtu	2.9				7.9
Change in net asset optimization (expense) revenue	(1.7		)		5.1
Change in total revenues	$	(192.2	)		$	207.8

Retail Cost of Revenues. Total retail cost of revenues for the year ended December 31, 2019 was approximately $615.2 million, a decrease of approximately $230.3 million, or 27%, from approximately $845.5 million for the year ended December 31, 2018. This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in 2019, a decrease in electricity and natural gas unit cost, and a change in fair value of our retail derivative portfolio. Total retail cost of revenues for the year ended December 31, 2018 increased approximately $293.3 million, or 53%, from approximately $552.2 million for the year ended December 31, 2017. This increase was primarily due to an increase in electricity volumes driven by the acquisitions of HIKO and two customer portfolios, full year results from the Verde Companies, higher-than-normal electricity and natural gas prices due to the extreme unpredictable weather in the first quarter of 2018, increased capacity costs in the second and third quarters of 2018, and additional hedges in ERCOT in the third quarter of 2018.

Analysis of the impact of changes in prices and volumes between the years ended December 31, 2019, 2018, and 2017 are as follows:

	2019 vs. 2018				2018 vs. 2017
Change in electricity volumes sold	$	(189.5	)		$	138.5
Change in natural gas volumes sold	(10.3		)		(5.9		)
Change in electricity unit cost per MWh	(21.4		)		101.2
Change in natural gas unit cost per MMBtu	(4.9		)		8.2
Change in value of retail derivative portfolio	(4.2		)		51.3
Change in retail cost of revenues	$	(230.3	)		$	293.3

General and Administrative Expense. General and administrative expense for the year ended December 31, 2019 was approximately $133.5 million, an increase of approximately $22.1 million, or 20%, as compared to $111.4 million for the year ended December 31, 2018. This increase was primarily attributable to non-recurring legal and regulatory settlements and increased litigation expense in 2019. General and administrative expense for the year ended December 31, 2018 increased approximately $10.3 million or 10%, as compared to $101.1 million for the year ended December 31, 2017. This increase was primarily attributable to reductions in the fair value of earnout liabilities, which decreased general and administrative expenses in 2017 to a greater extent than in 2018, increased commissions paid to commercial brokers, and variable costs associated with increased RCEs from our acquisitions.

Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2019 was approximately $41.0 million, a decrease of approximately $11.7 million, or 22%, from approximately $52.7 million for the year ended December 31, 2018. This decrease was primarily due to the decreased amortization expense associated with customer relationship intangibles. Depreciation and amortization expense for the year ended December 31, 2018 increased approximately $10.4 million, or 24%, from approximately $42.3 million for the year ended December 31, 2017. This increase was primarily due to the increased amortization expense associated with customer relationship intangibles from the acquisitions of the Verde Companies, HIKO and customers from an affiliate, and the write-off of assets no longer in use as a result of integration activities.

Customer Acquisition Cost. Customer acquisition cost for the year ended December 31, 2019 was approximately $18.7 million, an increase of approximately $5.0 million, or 37% from approximately $13.7 million for the year ended December 31, 2018. This increase was primarily due to an increase in the number of organic sales in 2019 as

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compared to 2018, as we had slowed our organic sales in 2018 to concentrate on acquisitions of companies and portfolios of customers. Customer acquisition cost for the year ended December 31, 2018 decreased approximately $12.2 million, or 47% from approximately $25.9 million for the year ended December 31, 2017. This decrease was primarily due to a decrease in the number of organic sales in 2018 as we were more focused on acquisitions of businesses, customer portfolio additions, and integration.

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Operating Segment Results 

	Year Ended December 31,
	2019				2018				2017
	(in thousands, except volume and per unit operating data)
Retail Electricity Segment
Total Revenues	$	688,451			$	863,451			$	657,566
Retail Cost of Revenues	552,250				762,771				477,012
Less: Net (Losses) Gains on non-trading derivatives, net of cash settlements	(24,339		)		(23,988		)		22,086
Retail Gross Margin (1) —Electricity	$	160,540			$	124,668			$	158,468
Volumes—Electricity (MWhs)	6,416,568				8,630,653				6,755,663
Retail Gross Margin (2) —Electricity per MWh	$	25.02			$	14.44			$	23.46
Retail Natural Gas Segment
Total Revenues	$	122,503			$	137,966			$	141,206
Retail Cost of Revenues	62,975				82,722				75,155
Less: Net (Losses) Gains on non-trading derivatives, net of cash settlements	(672		)		(5,197		)		10
Retail Gross Margin (1) —Gas	$	60,200			$	60,441			$	66,041
Volumes—Gas (MMBtus)	14,543,563				16,778,393				18,203,684
Retail Gross Margin (2) —Gas per MMBtu	$	4.14			$	3.60			$	3.63

(1) Reflects the Retail Gross Margin attributable to our Retail Electricity Segment or Retail Natural Gas Segment, as applicable. Retail Gross Margin is a non-GAAP financial measure. See “—Non-GAAP Performance Measures” for a reconciliation of Retail Gross Margin to most directly comparable financial measures presented in accordance with GAAP.

(2) Reflects the Retail Gross Margin for the Retail Electricity Segment or Retail Natural Gas Segment, as applicable, divided by the total volumes in MWh or MMBtu, respectively.

Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the year ended December 31, 2019 were approximately $688.5 million, a decrease of approximately $175.0 million, or 20%, from approximately $863.5 million for the year ended December 31, 2018. This decrease was largely due to lower volumes sold, resulting in a decrease of $221.5 million as a result of a smaller C&I customer book in 2019. This decrease was partially offset by higher weighted average electricity rates, due to our customer mix shifting away from large C&I customers, which resulted in an increase of $46.5 million. Total revenues for the Retail Electricity Segment for the year ended December 31, 2018 increased approximately $205.9 million, or 31%, from approximately $657.6 million for the year ended December 31, 2017. This increase was largely due to an increase in volumes, a result of our acquisitions of HIKO and two customer portfolios, full year results from the Verde Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in the second and third quarters of 2018, resulting in an increase of $182.5 million. This increase was further impacted by the higher electricity pricing environment, which resulted in an increase of $23.4 million.

Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2019 was approximately $552.3 million, a decrease of approximately $210.5 million, or 28%, from approximately $762.8 million for the year ended December 31, 2018. This decrease was primarily due to a decrease in volumes, resulting in a decrease of $189.5 million. This decrease was further impacted by decreased electricity supply costs, which resulted in a decrease in retail cost of revenues of $21.4 million. Additionally, there was an increase of $0.4 million due to a change in the value of our retail derivative portfolio used in hedging. Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2018 increased approximately $285.8 million, or 60%, from approximately $477.0 million for the year ended December 31, 2017. This increase was primarily due to an increase in volumes as a result of the acquisitions of HIKO and two customers portfolios, full year results from the Verde

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Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in second and third quarter of 2018, resulting in an increase of $138.5 million. This increase was further impacted by increased electricity prices, REC requirements and capacity costs, which resulted in an increase in retail cost of revenues of $101.2 million. Additionally, there was an increase of $46.1 million due to a change in the value of our retail derivative portfolio used in hedging.

Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2019 increased approximately $35.8 million, or 29%, as compared to the year ended December 31, 2018, and 2018 decreased approximately $33.8 million or 21% as compared to December 31, 2017 as indicated in the table below (in millions).

	2019 vs. 2018				2018 vs. 2017
Change in volumes sold	$	(32.0	)		$	44.0
Change in unit margin per MWh	67.8				(77.8		)
Change in retail electricity segment retail gross margin	$	35.8			$	(33.8	)

Unit margins were positively impacted in 2019 compared to prior year primarily as a result of the higher volumes from our residential customers, which tend to have higher unit margins than our C&I customers. Unit margins were negatively impacted in 2018 compared to prior year primarily as a result of higher volumes from our C&I customers.

The volumes of electricity sold decreased from 8,630,653 MWh for the year ended December 31, 2018 to 6,416,568 MWh for the year ended December 31, 2019. This decrease was primarily due to a smaller C&I customer book in 2019. The volumes of electricity sold increased from 6,755,663 MWh for the year ended December 31, 2017 to 8,630,653 MWh for the year ended December 31, 2018. This increase was primarily due to our acquisitions of HIKO and two customer portfolios, full year results from the Verde Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in the second and third quarters of 2018.

Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2019 were approximately $122.5 million, a decrease of approximately $15.5 million, or 11%, from approximately $138.0 million for the year ended December 31, 2018. This decrease was primarily attributable to a decrease in volumes of $18.4 million, offset by higher rates, which resulted in an increase in total revenues of $2.9 million. Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2018 decreased by approximately $3.2 million, or 2%, from approximately $141.2 million for the year ended December 31, 2017. This decrease was primarily attributable to an increase in price of $7.9 million, offset by a decrease in customer sales volume, which decreased total revenues by $11.1 million.

Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2019 were approximately $63.0 million, a decrease of approximately $19.7 million, or 24%, from approximately $82.7 million for the year ended December 31, 2018. This decrease was primarily due to decreased supply costs of $4.9 million, a decrease of $10.3 million related to decreased volumes, and a decrease of $4.5 million due to change in the fair value of our retail derivative portfolio used for hedging. Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2018 increased approximately $7.5 million, or 10%, from approximately $75.2 million for the year ended December 31, 2017. This increase was due to increased supply costs of $8.2 million, $5.2 million change in the fair value of our retail derivative portfolio used for hedging, offset by $5.9 million related to decreased volumes.

Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2019 decreased by approximately $0.2 million, or less than 1% from approximately $60.4 million for the year ended December 31,

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2018, and 2018 decreased approximately $5.6 million or 8% from approximately $66.0 million for the year ended December 31, 2017 as indicated in the table below (in millions).

	2019 vs. 2018				2018 vs. 2017
Change in volumes sold	$	(8.1	)		$	(5.2	)
Change in unit margin per MMBtu	7.9				(0.4		)
Change in retail natural gas segment retail gross margin	$	(0.2	)		$	(5.6	)

Unit margins were positively impacted in 2019 compared to prior year as a result of higher volumes from our residential customers, which tend to have higher unit margins than our C&I customers. Unit margins were negatively impacted in 2018 compared to prior year primarily as a result of higher volume from our C&I customers.

The volumes of natural gas sold decreased from 16,778,393 MMBtu for the year ended December 31, 2018 to 14,543,563 MMBtu for the year ended December 31, 2019. This decrease was primarily due to warmer-than-normal weather in the second and third quarters of 2019. The volumes of natural gas sold decreased from 18,203,684 MMBtu for the year ended December 31, 2017 to 16,778,393 MMBtu for the year ended December 31, 2018. This decrease was primarily due to warmer-than-normal weather in the second and third quarters of 2018.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations and borrowings under our Senior Credit Facility. Our principal liquidity requirements are to meet our financial commitments, finance current operations, fund organic growth and/or acquisitions, service debt and pay dividends. Our liquidity requirements fluctuate with our level of customer acquisition costs, acquisitions, collateral posting requirements on our derivative instruments portfolio, distributions, the effects of the timing between the settlement of payables and receivables, including the effect of bad debts, weather conditions, and our general working capital needs for ongoing operations. We believe that cash generated from operations and our available liquidity sources will be sufficient to sustain current operations and to pay required taxes and quarterly cash distributions, including the quarterly dividends to the holders of the Class A common stock and the Series A Preferred Stock, for the next twelve months. Estimating our liquidity requirements is highly dependent on then-current market conditions, including weather events, forward prices for natural gas and electricity, market volatility and our then existing capital structure and requirements.

We believe that the financing of any additional growth through acquisitions and/or the need for more liquidity in the first half of 2020 may require further equity or debt financing and/or further expansion of our Senior Credit Facility.

Liquidity Position

The following table details our available liquidity as of December 31, 2019:

	December 31,
($ in thousands)	2019
Cash and cash equivalents	$	56,664
Senior Credit Facility Availability (1)	57,068
Subordinated Debt Facility Availability (2)	25,000
Total Liquidity	$	138,732

(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of December 31, 2019.

(2) The availability of the Subordinated Facility is dependent on our Founder's willingness and ability to lend. See "—Sources of Liquidity—Subordinated Debt Facility."

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Borrowings and related posting of letters of credit under our Senior Credit Facility are subject to material variations on a seasonal basis due to the timing of commodity purchases to satisfy natural gas inventory requirements and to meet customer demands during periods of peak usage. Additionally, borrowings are subject to borrowing base and covenant restrictions.

Cash Flows

Our cash flows were as follows for the respective periods (in thousands):

	Year Ended December 31,
	2019				2018				2017
Net cash provided by operating activities	$	91,735			$	59,763			$	62,131
Net cash provided by (used in) investing activities	$	1,398			$	(18,981	)		$	(77,558	)
Net cash (used in) provided by financing activities	$	(85,103	)		$	(20,563	)		$	25,886

Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the year ended December 31, 2019 increased by $32.0 million compared to the year ended December 31, 2018. The increase was primarily the result of a higher net income in 2019 coupled with a decrease in the changes in working capital for the year ended December 31, 2019. Cash flows provided by operating activities for the year ended December 31, 2018 decreased by $2.4 million compared to the year ended December 31, 2017. The decrease was primarily the result of a decrease in the changes in working capital for the year ended December 31, 2018 and the impact of extreme weather events during the first quarter of 2018.

Cash Flows Provided by Investing Activities. Cash flows provided by investing activities increased by $20.4 million for the year ended December 31, 2019. The increase was primarily the result of a reduction in the amount of cash paid for acquisitions during the year ended December 31, 2019 compared to the year ended December 31, 2018, and proceeds received from the sale of the Company's equity method investment in 2019. Cash flows used in investing activities decreased by $58.6 million for the year ended December 31, 2018. The decrease was primarily the result of the $81.3 million acquisition of the Verde Companies, Perigee and other customers during the year ended December 31, 2017, offset by the acquisition of HIKO of $14.3 million during the year ended December 31, 2018.

Cash Flows Used in Financing Activities. Cash flows used in financing activities increased by $64.5 million for the year ended December 31, 2019. The increase in cash flows used in financing activities was primarily due to increased net paydown of our Senior Credit Facility and subordinated debt, as well as payments to settle the Company's Tax Receivable Agreement liability. In addition, for the year ended December 31, 2018, we received proceeds from the issuance of Series A Preferred Stock of approximately $48.5 million, which did not reoccur during 2019. Cash flows used in financing activities increased by $46.4 million for the year ended December 31, 2018. The increase in cash flows used in financing activities was primarily due to increased net paydown of our Senior Credit Facility, additional dividends paid to holders of Series A Preferred Stock, payments related to the Verde Promissory Note and payments associated with the acquisition of customers from an affiliate for the year ended December 31, 2018.

Sources of Liquidity and Capital Resources

Senior Credit Facility

As of December 31, 2019, we had total commitments of $217.5 million, of which $160.4 million was outstanding, including $37.4 million of outstanding letters of credit. In January 2019, our total commitments under our Senior Credit Facility increased to $217.5 million. Under the Senior Credit Facility, we have various limits on advances for Working Capital Loans, Letters of Credit and Bridge Loans. The Senior Credit Facility matures on May 19, 2021. For a description of the terms and conditions of our Senior Credit Facility, including descriptions of the interest rate, commitment fee, covenants and terms of default, please see Note 10 "Debt" in the notes to our

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consolidated financial statements. As of December 31, 2019, we were in compliance with the covenants under our Senior Credit Facility.

Amended and Restated Subordinated Debt Facility

 

Our Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to $25.0 million. Although we may use the Subordinated Debt Facility from time to time to enhance short term liquidity, we do not view the Subordinated Debt Facility as a material source of liquidity. See Note 10 "Debt" for additional details. As of December 31, 2019, there was zero outstanding borrowings under the Subordinated Debt Facility.

Uses of Liquidity and Capital Resources

Repayment of Current Portion of Senior Credit Facility

Our Senior Credit Facility matures in 2021, and thus, no amounts are due currently. However, due to the revolving nature of the facility, excess cash available is generally used to reduce the balance outstanding, which at December 31, 2019 was $123.0 million. The current variable interest rate on the facility at December 31, 2019 was 4.71%.

Customer Acquisitions

Our customer acquisition strategy consists of customer growth obtained through organic customer additions as well as opportunistic acquisitions. During the years ended December 31, 2019 and 2018, we spent a total of $18.7 million and $13.7 million, respectively, on organic customer acquisitions. Our ability to grow our customer base organically or by acquisition is important to our success as we experience ongoing customer attrition each period.

Capital Expenditures

Our capital requirements each year are relatively low and generally consist of minor purchases of equipment or information system upgrades and improvements. Capital expenditures for the year ended December 31, 2019 included approximately $1.1 million related to information systems improvements.

Dividends and Distributions

For the year ended December 31, 2019, we paid dividends to holders of our Class A common stock of $0.725 per share or $10.4 million in the aggregate. In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of Class B common stock (our non-controlling interest holders). As a result, during the year ended December 31, 2019, Spark HoldCo made distributions of $15.1 million to our non-controlling interest holders related to the dividend payments to our Class A shareholders.

For the year ended December 31, 2019, we paid $8.1 million of dividends to holders of our Series A Preferred Stock, and as of December 31, 2019, we had accrued $2.0 million related to dividends to holders of our Series A Preferred Stock, which we paid on January 15, 2020. For the year ended December 31, 2019, we declared dividends of $2.1875 per share or $8.1 million in the aggregate on our Series A Preferred Stock.

On January 21, 2020, our Board of Directors declared a quarterly cash dividend in the amount of $0.18125 per share to holders of our Class A common stock and $0.546875 per share for the Series A Preferred Stock. Dividends on Class A common stock will be paid on March 16, 2020 to holders of record on March 2, 2020 and Series A Preferred Stock dividends will be paid on April 15, 2020 to holders of record on April 1, 2020.

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Our ability to pay dividends in the future will depend on many factors, including the performance of our business and restrictions under our Senior Credit Facility. If our business does not generate sufficient cash for Spark HoldCo to make distributions to us to fund our Class A common stock and Series A Preferred Stock dividends, we may have to borrow to pay such amounts. Further, even if our business generates cash in excess of our current annual dividend (of $0.725 per share on our Class A common stock), we may reinvest such excess cash flows in our business and not increase the dividends payable to holders of our Class A common stock. Our future dividend policy is within the discretion of our Board of Directors and will depend upon the results of our operations, our financial condition, capital requirements and investment opportunities.

Verde Promissory Note

In January 2018, we issued an amended and restated promissory note to the sellers of the Verde Companies (the "Verde Promissory Note"). As of December 31, 2018, there was $1.0 million outstanding under the Verde Promissory Note, all of which was paid in January 2019. The note bore interest at 9% per annum, and we made monthly payments of principal and associated interest, a portion of which was deposited into an escrow account to provide security for certain indemnification claims and obligations under the Verde purchase agreement. As of December 31, 2019 and 2018, a total of $5.3 million and $7.6 million was held in escrow for such claims.

Verde Earnout Termination Note

In January 2018, we issued a promissory note in the principal amount of $5.9 million in connection with an agreement to terminate the earnout obligation arising in connection with our acquisition of the Verde Companies (the "Verde Earnout Termination Note"). The Verde Earnout Termination Note matured in June 2019 and bore interest at a rate of 9% per annum. Under the terms of the Verde Earnout Termination Note, we were permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters. A payment of $1.0 million was made to the seller of the Verde Companies in June 2019, and $4.9 million was withheld (the “Verde Holdback”) to be applied to indemnifiable matters. As of December 31, 2019 and 2018, there was zero and $5.9 million outstanding under the Verde Earnout Termination Note, respectively.

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Summary of Contractual Obligations

The following table discloses aggregate information about our contractual obligations and commercial commitments as of December 31, 2019 (in millions): 

	Total			2020			2021			2022			2023			2024			> 5 years
Purchase obligations:
Pipeline transportation agreements	$	6.6		$	0.9		$	1.5		$	0.7		$	0.7		$	0.7		$	2.1
Other purchase obligations (1)	9.4			6.1			2.8			0.5			—			—			—
Total purchase obligations	$	16.0		$	7.0		$	4.3		$	1.2		$	0.7		$	0.7		$	2.1
Senior Credit Facility	$	123.0		$	—		$	123.0		$	—		$	—		$	—		$	—
Debt	$	123.0		$	—		$	123.0		$	—		$	—		$	—		$	—

(1)	The amounts presented here include contracts for billing services and other software agreements to support our operations.

Off-Balance Sheet Arrangements

As of December 31, 2019, we had no material "off-balance sheet arrangements."

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Related Party Transactions

For a discussion of related party transactions, see Note 15 "Transactions with Affiliates" in the Company’s audited consolidated financial statements.

Critical Accounting Policies and Estimates

Our significant accounting policies are described in Note 2 "Basis of Presentation and Summary of Significant Accounting Policies" to our audited consolidated financial statements. We prepare our financial statements in conformity with accounting principles generally accepted in the United States of America and pursuant to the rules and regulations of the SEC, which require us to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying footnotes. Actual results could differ from those estimates. We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our financial statements and the uncertainties that could impact our financial condition and results of operations.

Revenue Recognition and Retail Cost of Revenues

Our revenues are derived primarily from the sale of natural gas and electricity to retail customers. We also record revenues from sales of natural gas and electricity to wholesale counterparties, including affiliates. Revenues are recognized when the natural gas or electricity is delivered. Similarly, cost of revenues is recognized when the commodity is delivered.

In each period, natural gas and electricity that has been delivered but not billed by period is estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter read and are provided by the utility. Volume estimates are based on forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.

The cost of natural gas and electricity for sale to retail customers is similarly based on estimated supply volumes for the applicable reporting period. In estimating supply volumes, we consider the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution delivery fees, where applicable, are estimated using the same method used for sales to retail customers. In addition, other load related costs, such as ISO fees, ancillary services and renewable energy credits are estimated based on historical trends, estimated supply volumes and initial utility data. Volume estimates are then multiplied by the supply rate and recorded as retail cost of revenues in the applicable reporting period. Estimated amounts are adjusted when actual usage is known and billed.

Business Combinations

When we acquire a business or a book of customers, we assign and allocate the purchase price to the identifiable assets acquired and liabilities assumed based upon their estimated fair value. Generally, the amount recorded in the financial statements for an acquisition’s assets and liabilities is equal to the purchase price (the fair value of the consideration paid); however, when the purchase price exceeds the underlying fair value of the net assets acquired, we recognize goodwill. Conversely, a purchase price that is below the fair value of the net assets acquired will result in the recognition of a bargain purchase in the income statement.

In addition to the potential for the recognition of goodwill or a bargain purchase, differing fair values will impact the allocation of the purchase price to the individual assets and liabilities and can impact the gross amount and classification of assets and liabilities recorded in our consolidated balance sheets, which can impact the timing and amount of depreciation and amortization expense recorded in any given period.

In estimating fair value, we use discounted cash flow (“DCF”) projections, recent comparable market transactions, if available, or quoted prices. We consider assumptions that third parties would make in estimating fair value,

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including, but not limited to, the highest and best use of the asset. There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates, commodity prices, customer attrition, useful lives and growth factors. The assumptions used by another party could differ significantly from our assumptions.

We utilize our best effort to make our determinations and review all information available, including estimated future cash flows and prices of similar assets when making our best estimate. We also may hire independent appraisers or valuation specialists to help us make this determination as we deem appropriate under the circumstances. Refer to Note 4 "Acquisitions" for further discussion of assumptions used in acquisitions.

There is a significant amount of judgment in determining the fair value of acquisitions and in allocating the purchase price to individual assets and liabilities. Had different assumptions been used, the fair value of the assets acquired and liabilities assumed could have been significantly higher or lower with a corresponding increase or reduction in recognized goodwill, or could have required recognition of a bargain purchase.

In the case of acquisitions that involve potential future contingent consideration, we record on the date of acquisition a liability equal to the fair value of the estimated additional consideration we may be obligated to pay in the future. We re-measure this liability each reporting period and record changes in the fair value as general and administrative expense. Increase or decreases in the fair value of the contingent consideration can result from changes in in the timing or likelihood of achieving revenue or customer count thresholds. The use of alternative valuation assumptions, including estimated revenue projections, growth rates, cash flows and discount rates and alternative estimated probabilities surrounding revenue or customer count thresholds could result in different expense related to contingent consideration.

Goodwill

As noted above, Goodwill represents the excess of cost over fair value of the assets of businesses. The goodwill on our consolidated balance sheet as of December 31, 2019 is associated with both our Retail Natural Gas and Retail Electricity reporting units. We determine our reporting units by identifying each unit that is engaged in business activities from which it may earn revenues and incur expenses, has operating results regularly reviewed by the segment manager for purposes of resource allocation and performance assessment, and has discrete financial information.

Goodwill is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. Our annual assessment, absent a triggering event is as of October 31 of each year. On October 31, 2019, we elected to perform a qualitative assessment of goodwill in accordance with guidance from ASC 350. This guidance permits an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the quantitative goodwill impairment test. If we fail the qualitative test or if we elect to by-pass the qualitative assessment, then we must compare our estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we would recognize a goodwill impairment loss for the amount by which the reporting unit’s carrying value exceeds its fair value. All of these assessments and calculations, including the determination of whether a triggering event has occurred to undertake an assessment of goodwill involve a high degree of judgment.

We completed our annual assessment of goodwill impairment at October 31, 2019, and the test indicated no impairment.

Deferred tax assets and liabilities

The Company recognizes the amount of taxes payable or refundable for each tax year. In addition, the Company follows the asset and liability method of accounting for income taxes where deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns and operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax

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rates expected to apply to taxable income in those years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the projected future taxable income and tax planning strategies in making this assessment. All of these determinations involve estimates and assumptions.

Recent Accounting Pronouncements

Refer to Note 2 "Basis of Presentation and Summary of Significant Accounting Policies" for a discussion of recent accounting pronouncements.

Contingencies

In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including regulatory and other matters. Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. For a discussion of the status of current legal and regulatory matters, see Note 14 "Commitments and Contingencies" in the Company’s audited consolidated financial statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risks relating to our operations result primarily from changes in commodity prices and interest rates, as well as counterparty credit risk. We employ established risk management policies and procedures to manage, measure, and limit our exposure to these risks.

Commodity Price Risk

We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets and through short and long-term contracts. Our financial results are largely dependent on the margin we are able to realize between the wholesale purchase price of natural gas and electricity plus related costs and the retail sales price we charge our customers for these commodities. We actively manage our commodity price risk by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from fixed-price forecasted sales and purchases of natural gas and electricity in connection with our retail energy operations. These instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as NYMEX and Intercontinental Exchange, or ICE, as well as over-the-counter markets. These contracts have varying terms and durations, which range from a few days to several years, depending on the instrument. We also utilize similar derivative contracts in connection with our asset optimization activities to attempt to generate incremental gross margin by effecting transactions in markets where we have a retail presence. Generally, any such instruments that are entered into to support our retail electricity and natural gas business are categorized as having been entered into for non-trading purposes, and instruments entered into for any other purpose are categorized as having been entered into for trading purposes.

Our net loss on our non-trading derivative instruments, net of cash settlements, was $25.0 million for the year ended December 31, 2019.

We have adopted risk management policies to measure and limit market risk associated with our fixed-price portfolio and our hedging activities.

We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis on our net open position. As of December 31, 2019, our Gas Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 388,833 MMBtu. An increase of 10% in the market prices (NYMEX) from their December 31, 2019 levels would have increased the fair market value of our net non-trading energy portfolio by $0.1 million. Likewise, a decrease of 10% in the market prices (NYMEX) from their December 31, 2019 levels would have decreased the fair market value of our non-trading energy derivatives by $0.1 million. As of December 31, 2019, our Electricity Non-Trading Fixed Price Open Position (hedges net of retail load) was a short position of 182,509 MWhs. An increase of 10% in the forward market prices from their December 31, 2019 levels would have decreased the fair market value of our net non-trading energy portfolio by $0.4 million. Likewise, a decrease of 10% in the forward market prices from their December 31, 2019 levels would have increased the fair market value of our non-trading energy derivatives by $0.4 million.

Credit Risk

In many of the utility services territories where we conduct business, Purchase of Receivables ("POR") programs have been established, whereby the local regulated utility purchases our receivables, and becomes responsible for billing the customer and collecting payment from the customer. This service results in substantially all of our credit risk being with the utility and not to our end-use customer in these territories. Approximately 67%, 66% and 66% of our retail revenues were derived from territories in which substantially all of our credit risk was with local regulated utility companies as of December 31, 2019, 2018 and 2017, respectively, all of which had investment grade ratings as of such date. During the same period, we paid these local regulated utilities a weighted average discount of approximately 0.8%, 1.0% and 1.1%, respectively, of total revenues for customer credit risk protection. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period.

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If our collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer's expected commodity usage for the life of the contract.

In non-POR markets (and in POR markets where we may choose to direct bill our customers), we manage customer credit risk through formal credit review in the case of commercial customers, and credit score screening, deposits and disconnection for non-payment, in the case of residential customers. Economic conditions may affect our customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense. Our bad debt expense for the year ended December 31, 2019, 2018 and 2017 was approximately 3.3%, 2.6% and 2.5% of non-POR market retail revenues, respectively. See “Management's Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for an analysis of our bad debt expense related to non-POR markets during 2019.

We are exposed to wholesale counterparty credit risk in our retail and asset optimization activities. We manage this risk at a counterparty level and secure our exposure with collateral or guarantees when needed. At December 31, 2019 and 2018, approximately $0.1 million and $4.1 million of our total exposure of $3.1 million and $22.7 million, respectively, was either with a non-investment grade counterparty or otherwise not secured with collateral or a guarantee. The credit worthiness of the remaining exposure with other customers was evaluated with no material allowance recorded at December 31, 2019 and 2018.

Interest Rate Risk

We are exposed to fluctuations in interest rates under our variable-price debt obligations. At December 31, 2019, we were co-borrowers under the Senior Credit Facility, under which $123.0 million of variable rate indebtedness was outstanding. Based on the average amount of our variable rate indebtedness outstanding during the year ended December 31, 2019, a 1% percent increase in interest rates would have resulted in additional annual interest expense of approximately $1.2 million. We currently have two interest rate swap agreements to manage interest rate risk.

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Item 8. Financial Statements and Supplementary Data

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING		64
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS		65
CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2019 AND DECEMBER 31, 2018		68
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017		70
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017		71
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017		73
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS		75

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MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

It is the responsibility of the management of Spark Energy, Inc. to establish and maintain adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

•	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions and dispositions of the assets;

•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, utilizing the criteria in the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control-Integrated Framework (2013). Based on its assessment, our management concluded the Company’s internal control over financial reporting was effective as of December 31, 2019.

Ernst & Young LLP, an independent registered public accounting firm, who audited the Company's consolidated financial statements included in this Form 10-K, has issued an attestation report on the Company's internal control over financial reporting, which is included herein.

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Spark Energy, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Spark Energy, Inc. (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations and comprehensive income (loss), changes in equity and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 5, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as Spark Energy, Inc.’s auditor since 2018.

Houston, Texas

March 5, 2020

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of Spark Energy, Inc.

Opinion on Internal Control over Financial Reporting

We have audited Spark Energy, Inc.’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Spark Energy, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of Spark Energy, Inc. as of December 31, 2019 and 2018, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”), and our report dated March 5, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

March 5, 2020

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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Spark Energy, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated statements of operations and comprehensive income (loss), changes in equity, and cash flows of Spark Energy, Inc. and subsidiaries (the Company) for the year ended December 31, 2017, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the results of the Company’s operations and its cash flows for the year ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ KPMG LLP

We served as the Company’s auditor from 2011 to 2018.

Houston, Texas

March 9, 2018, except for note 3, as to which the date is March 5, 2020.

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AUDITED CONSOLIDATED FINANCIAL STATEMENTS

SPARK ENERGY, INC.

CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2019 AND DECEMBER 31, 2018

(in thousands, except share counts)

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	December 31, 2019					December 31, 2018
Assets
Current assets:
Cash and cash equivalents	$	56,664				$	41,002
Restricted cash	1,004					8,636
Accounts receivable, net of allowance for doubtful accounts of $4,797 and $3,353 as of December 31, 2019 and 2018, respectively	113,635					150,866
Accounts receivable—affiliates	2,032					2,558
Inventory	2,954					3,878
Fair value of derivative assets	464					7,289
Customer acquisition costs, net	8,649					14,431
Customer relationships, net	13,607					16,630
Deposits	6,806					9,226
Renewable energy credit asset	24,204					25,717
Other current assets	6,109					11,747
Total current assets	236,128					291,980
Property and equipment, net	3,267					4,366
Fair value of derivative assets	106					3,276
Customer acquisition costs, net	9,845					3,893
Customer relationships, net	17,767					26,429
Deferred tax assets	29,865					27,321
Goodwill	120,343					120,343
Other assets	5,647					11,130
Total Assets	$	422,968				$	488,738
Liabilities, Series A Preferred Stock and Stockholders' Equity
Current liabilities:
Accounts payable	$	48,245				$	68,790
Accounts payable—affiliates	1,009					2,464
Accrued liabilities	37,941					10,845
Renewable energy credit liability	33,120					42,805
Fair value of derivative liabilities	19,943					6,478
Current payable pursuant to tax receivable agreement—affiliates	—					1,658
Current contingent consideration for acquisitions	—					1,328
Current portion of note payable	—					6,936
Other current liabilities	1,697					647
Total current liabilities	141,955					141,951
Long-term liabilities:
Fair value of derivative liabilities	495					106
Payable pursuant to tax receivable agreement—affiliates	—					25,917
Long-term portion of Senior Credit Facility	123,000					129,500
Subordinated debt—affiliate	—					10,000
Other long-term liabilities	217					212
Total liabilities	265,667					307,686
Commitments and contingencies (Note 14)
Series A Preferred Stock, par value $0.01 per share, 20,000,000 shares authorized, 3,707,256 shares issued and 3,677,318 shares outstanding at December 31, 2019 and 3,707,256 shares issued and outstanding at December 31, 2018	90,015					90,758
Stockholders' equity:
Common Stock :
Class A common stock, par value $0.01 per share, 120,000,000 shares authorized, 14,478,999 issued and 14,379,553 outstanding at December 31, 2019 and 14,178,284 issued and 14,078,838 outstanding at December 31, 2018	145					142
Class B common stock, par value $0.01 per share, 60,000,000 shares authorized, 20,800,000 issued and outstanding at December 31, 2019 and 20,800,000 issued and outstanding at December 31, 2018	209					209
Additional paid-in capital	51,842					46,157
Accumulated other comprehensive (loss)/income	(40		)			2
Retained earnings	1,074					1,307
Treasury stock, at cost, 99,446 shares at December 31, 2019 and December 31, 2018	(2,011		)			(2,011		)
Total stockholders' equity	51,219					45,806
Non-controlling interest in Spark HoldCo, LLC	16,067					44,488
Total equity	67,286					90,294
Total Liabilities, Series A Preferred Stock and stockholders' equity	$	422,968				$	488,738

The accompanying notes are an integral part of the consolidated financial statements.

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SPARK ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 and 2017

(in thousands, except per share data)

	Year Ended December 31,
	2019				2018				2017
Revenues:
Retail revenues	$	810,954			$	1,001,417			$	798,772
Net asset optimization revenues (expense)	2,771				4,511				(717		)
Total revenues	813,725				1,005,928				798,055
Operating expenses:
Retail cost of revenues	615,225				845,493				552,167
General and administrative	133,534				111,431				101,127
Depreciation and amortization	40,987				52,658				42,341
Total operating expenses	789,746				1,009,582				695,635
Operating income (loss)	23,979				(3,654		)		102,420
Other (expense)/income:
Interest expense	(8,621		)		(9,410		)		(11,134		)
Change in tax receivable agreement liability	—				—				22,267
Gain on disposal of eRex	4,862				—				—
Total other income/(expense)	1,250				749				256
Total other (expense)/income	(2,509		)		(8,661		)		11,389
Income (loss) before income tax expense	21,470				(12,315		)		113,809
Income tax expense	7,257				2,077				38,765
Net income (loss)	$	14,213			$	(14,392	)		$	75,044
Less: Net income (loss) attributable to non-controlling interest	5,763				(13,206		)		55,799
Net income (loss) attributable to Spark Energy, Inc. stockholders	$	8,450			$	(1,186	)		$	19,245
Less: Dividend on Series A preferred stock	8,091				8,109				3,038
Net income (loss) attributable to stockholders of Class A common stock	$	359			$	(9,295	)		$	16,207
Other comprehensive (loss) income, net of tax:
Currency translation (loss) gain	(102		)		31				(59		)
Other comprehensive (loss) income	(102		)		31				(59		)
Comprehensive income (loss)	$	14,111			$	(14,361	)		$	74,985
Less: Comprehensive income (loss) attributable to non-controlling interest	5,703				(13,188		)		55,762
Comprehensive income (loss) attributable to Spark Energy, Inc. stockholders	$	8,408			$	(1,173	)		$	19,223
Net income (loss) attributable to Spark Energy, Inc. per share of Class A common stock
Basic	$	0.03			$	(0.69	)		$	1.23
Diluted	$	0.02			$	(0.69	)		$	1.21
Weighted average shares of Class A common stock outstanding
Basic	14,286				13,390				13,143
Diluted	14,568				13,390				13,346

The accompanying notes are an integral part of the consolidated financial statements.

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SPARK ENERGY, INC.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 and 2017

(in thousands)

	Issued Shares of Class A Common Stock		Issued Shares of Class B Common Stock		Treasury Stock		Class A Common Stock			Class B Common Stock			Treasury Stock			Accumulated Other Comprehensive Income (Loss)			Additional Paid-In Capital			Retained Earnings (Deficit)			Total Stockholders' Equity			Non-controlling Interest			Total Equity
Balance at 12/31/2016:	12,993		20,450		—		$	130		$	206		$	—		$	11		$	39,187		$	4,711		$	44,245		$	72,010		$	116,255
Stock based compensation	—		—		—		—			—			—			—			2,754			—			2,754			—			2,754
Restricted stock unit vesting	242		—		—		2			—			—			—			1,052			—			1,054			—			1,054
Consolidated net income	—		—		—		—			—			—			—			—			19,245			19,245			55,799			75,044
Foreign currency translation adjustment for equity method investee	—		—		—		—			—			—			(22		)	—			—			(22		)	(37		)	(59		)
Beneficial conversion feature	—		—		—		—			—			—			—			—			—			—			176			176
Distributions paid to non-controlling unit holders	—		—		—		—			—			—			—			—			—			—			(33,800		)	(33,800		)
Net contribution by NG&E	—		—		—		—			—			—			—			—			—			—			274			274
Dividends paid to Class A common stockholders ($0.725 per share)	—		—		—		—			—			—			—			—			(9,519		)	(9,519		)	—			(9,519		)
Dividends to Preferred Stock	—		—		—		—			—			—			—			—			(3,038		)	(3,038		)	—			(3,038		)
Proceeds from disgorgement of stockholder short-swing profits	—		—		—		—			—			—			—			708			—			708			—			708
Tax receivable agreement liability true-up	—		—		—		—			—			—			—			(2,872		)	—			(2,872		)	—			(2,872		)
Conversion of Convertible Subordinated Notes to Class B Common Stock	—		1,035		—		—			10			—			—			—			—			10			7,608			7,618
Treasury Stock	—		—		(99	)	—			—			(2,011		)	—			—			—			(2,011		)	—			(2,011		)
Remeasurement of deferred tax assets	—		—		—		—			—			—			—			6,511			—			6,511			—			6,511
Changes in ownership interest	—		—		—		—			—			—			—			471			—			471			(471		)	—
Balance at 12/31/2017:	13,235		21,485		(99	)	$	132		$	216		$	(2,011	)	$	(11	)	$	47,811		$	11,399		$	57,536		$	101,559		$	159,095
Stock based compensation	—		—		—		—			—			—			—			5,703			—			5,703			—			5,703
Restricted stock unit vesting	258		—		—		3			—			—			—			(1,018		)	—			(1,015		)	—			(1,015		)
Consolidated net income	—		—		—		—			—			—			—			—			(1,186		)	(1,186		)	(13,206		)	(14,392		)
Foreign currency translation adjustment for equity method investee	—		—		—		—			—			—			13			—			—			13			18			31

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Distributions paid to non-controlling unit holders	—		—		—		—			—			—			—			—			—			—			(35,478		)	(35,478		)
Dividends paid to Class A common stockholders ($0.725 per share)	—		—		—		—			—			—			—			(4,932		)	(4,851		)	(9,783		)	—			(9,783		)
Dividends to Preferred Stock	—		—		—		—			—			—			—			(4,055		)	(4,055		)	(8,110		)	—			(8,110		)
Exchange of shares of Class B common stock to shares of Class A common stock	685		(685	)	—		7			(7		)	—			—			—			—			—			—			—
Acquisition of Customers from Affiliate	—		—		—		—			—			—			—			—			—			—			(7,129		)	(7,129		)
Remeasurement of deferred tax assets	—		—		—		—			—			—			—			1,372			—			1,372			—			1,372
Changes in ownership interest	—		—		—		—			—			—			—			1,276			—			1,276			(1,276		)	—
Balance at 12/31/2018:	14,178		20,800		(99	)	$	142		$	209		$	(2,011	)	$	2		$	46,157		$	1,307		$	45,806		$	44,488		$	90,294
Stock based compensation	—		—		—		—			—			—			—			5,271			—			5,271			—			5,271
Restricted stock unit vesting	301		—		—		3			—			—			—			(1,107		)	—			(1,104		)	—			(1,104		)
Consolidated net income	—		—		—		—			—			—			—			—			8,450			8,450			5,763			14,213
Foreign currency translation adjustment for equity method investee	—		—		—		—			—			—			(42		)	—			—			(42		)	(60		)	(102		)
Gain on settlement of TRA, net of tax	—		—		—		—			—			—			—			11,951			—			11,951			—			11,951
Distributions paid to non-controlling unit holders	—		—		—		—			—			—			—			—			—			—			(34,794		)	(34,794		)
Dividends paid to Class A common stockholders ($0.725 per share)	—		—		—		—			—			—			—			(7,776		)	(2,606		)	(10,382		)	—			(10,382		)
Changes in ownership interest	—		—		—		—			—			—			—			(680		)	—			(680		)	680			—
Dividends to Preferred Shareholders	—		—		—		—			—			—			—			(2,029		)	(6,077		)	(8,106		)	—			(8,106		)
Proceeds from disgorgement of stockholder short-swing profits	—		—		—		—			—			—			—			55			—			55			—			55
Acquisition of Customers from Affiliate	—		—		—		—			—			—			—			—			—			—			(10		)	(10		)
Balance at 12/31/2019:	14,479		20,800		(99	)	$	145		$	209		$	(2,011	)	$	(40	)	$	51,842		$	1,074		$	51,219		$	16,067		$	67,286

The accompanying notes are an integral part of the consolidated financial statements.

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SPARK ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2019, 2018 AND 2017

(in thousands)

	Year Ended December 31,
	2019				2018				2017
Cash flows from operating activities:
Net income (loss)	$	14,213			$	(14,392	)		$	75,044
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization expense	41,002				51,436				42,666
Deferred income taxes	(6,929		)		(2,328		)		29,821
Change in TRA liability	—				—				(22,267		)
Stock based compensation	5,487				5,879				5,058
Amortization of deferred financing costs	1,275				1,291				1,035
Change in fair value of earnout liabilities	(1,328		)		(1,715		)		(7,898		)
Accretion on fair value of earnout liabilities	—				—				4,108
Excess tax expense (benefit) related to restricted stock vesting	50				(101		)		179
Bad debt expense	13,532				10,135				6,550
Loss (gain) on derivatives, net	67,749				18,170				(5,008		)
Current period cash settlements on derivatives, net	(41,919		)		11,038				(19,598		)
Accretion of discount to convertible subordinated notes to affiliate	—				—				1,004
Earnout payments	—				—				(1,781		)
Gain on disposal of eRex	(4,862		)		—				—
Other	(776		)		(882		)		(5		)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable	23,699				2,692				(32,361		)
Decrease (increase) in accounts receivable—affiliates	526				859				(1,459		)
Decrease (increase) in inventory	924				674				(718		)
Increase in customer acquisition costs	(18,685		)		(13,673		)		(25,874		)
Decrease (increase) in prepaid and other current assets	9,250				(14,033		)		1,915
Decrease (increase) in other assets	55				(335		)		(465		)
(Decrease) increase in accounts payable and accrued liabilities	(8,620		)		10,301				14,831
(Decrease) increase in accounts payable—affiliates	(1,455		)		(2,158		)		51
Decrease in other current liabilities	(1,459		)		(3,050		)		(1,210		)
Increase (decrease) in other non-current liabilities	6				41				(1,487		)
Decrease in intangible assets—customer acquisitions	—				(86		)		—
Net cash provided by operating activities	91,735				59,763				62,131
Cash flows from investing activities:
Purchases of property and equipment	(1,120		)		(1,429		)		(1,704		)
Cash paid for acquisitions	—				(17,552		)		(75,854		)
Acquisition of Starion Customers	(5,913		)		—				—
Disposal of eRex investment	8,431				—				—
Net cash provided by (used in) investing activities	1,398				(18,981		)		(77,558		)
Cash flows from financing activities:
Proceeds from (buyback) issuance of Series A Preferred Stock, net of issuance costs paid	(743		)		48,490				40,241
Payment to affiliates for acquisition of customer book	(10		)		(7,129		)		—
Borrowings on notes payable	356,000				417,300				206,400
Payments on notes payable	(362,500		)		(403,050		)		(152,939		)
Earnout Payments	—				(1,607		)		(18,418		)
Net paydown on subordinated debt facility	(10,000		)		—				—
Payments on the Verde promissory note	(2,036		)		(13,422		)		—
Restricted stock vesting	(1,348		)		(2,895		)		(3,091		)
Proceeds from disgorgement of stockholders short-swing profits	55				244				1,129
Payment of Tax Receivable Agreement Liability	(11,239		)		(6,219		)		—
Payment of dividends to Class A common stockholders	(10,382		)		(9,783		)		(9,519		)
Payment of distributions to non-controlling unitholders	(34,794		)		(35,478		)		(33,800		)
Payment of Preferred Stock dividends	(8,106		)		(7,014		)		(2,106		)
Purchase of Treasury Stock	—				—				(2,011		)
Net cash (used in) provided by financing activities	(85,103		)		(20,563		)		25,886
Increase in Cash and cash equivalents and Restricted Cash	8,030				20,219				10,459
Cash and cash equivalents and Restricted cash—beginning of period	49,638				29,419				18,960
Cash and cash equivalents and Restricted cash—end of period	$	57,668			$	49,638			$	29,419
Supplemental Disclosure of Cash Flow Information:
Non-cash items:
Property and equipment purchase accrual	$	92			$	(123	)		$	91
Holdback for Verde Note—Indemnified Matters	$	4,900			$	—			$	—

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Write-off of tax benefit related to tax receivable agreement liability—affiliates	$	4,384			$	—			$	—
Gain on settlement of tax receivable agreement liability—affiliates	$	16,336			$	—			$	—
Net contribution by NG&E in excess of cash	$	—			$	—			$	274
Installment consideration incurred in connection with the Verde Companies acquisition and Verde Earnout Termination Note	$	—			$	—			$	19,994
Tax benefit from tax receivable agreement	$	—			$	(1,508	)		$	(1,802	)
Liability due to tax receivable agreement	$	—			$	1,642			$	4,674
Cash paid during the period for:
Interest	$	6,634			$	7,883			$	5,715
Taxes	$	7,516			$	8,561			$	11,205

The accompanying notes are an integral part of the consolidated financial statements.

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SPARK ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Formation and Organization

We are an independent retail energy services company that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. The Company is a holding company whose sole material asset consists of units in Spark HoldCo, LLC (“Spark HoldCo”). The Company is the sole managing member of Spark HoldCo, is responsible for all operational, management and administrative decisions relating to Spark HoldCo’s business and consolidates the financial results of Spark HoldCo and its subsidiaries. Spark HoldCo is the direct and indirect owner of the subsidiaries through which we operate. We conduct our business through several brands across our service areas, including CenStar Energy, Electricity Maine, Electricity N.H., HIKO Energy, Major Energy, Oasis Energy, Perigee Energy, Provider Power Massachusetts, Respond Power, Spark Energy, and Verde Energy.

2. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Our financial statements are presented on a consolidated basis and include all wholly-owned and controlled subsidiaries. We account for investments over which we have significant influence but not a controlling financial interest using the equity method of accounting. All significant intercompany transactions and balances have been eliminated in the consolidated financial statements.

In the opinion of the Company's management, the accompanying consolidated financial statements reflect all adjustments that are necessary to fairly present the financial position, the results of operations, the changes in equity and the cash flows of the Company for the respective periods. Such adjustments are of a normal recurring nature, unless otherwise disclosed.

Subsequent Events

Subsequent events have been evaluated through the date these financial statements are issued. Any material subsequent events that occurred prior to such date have been properly recognized or disclosed in the consolidated financial statements.

Use of Estimates and Assumptions

The preparation of our consolidated financial statements requires estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results could materially differ from those estimates.

Relationship with our Founder and Majority Shareholder

W. Keith Maxwell, III (our "Founder") is the owner of a majority of the voting power of our common stock through his ownership of NuDevco Retail, LLC ("NuDevco Retail") and Retailco, LLC ("Retailco"). Retailco is a wholly owned subsidiary of TxEx Energy Investments, LLC ("TxEx"), which is wholly owned by Mr. Maxwell. NuDevco Retail is a wholly owned subsidiary of NuDevco Retail Holdings LLC ("NuDevco Retail Holdings"), which is a wholly owned subsidiary of Electric HoldCo, LLC, which is also a wholly owned subsidiary of TxEx.

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We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled by Mr. Maxwell, and these affiliates enter into transactions with and pay certain costs on our behalf. We undertake these transactions in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services among these related parties.

These transactions include, but are not limited to, employee benefits provided through the Company’s benefit plans, insurance plans, leased office space, certain administrative salaries, management due diligence, recurring management consulting, and accounting, tax, legal, or technology services. Amounts billed under these arrangements are based on services provided, departmental usage, or headcount, which are considered reasonable by management. As such, the accompanying consolidated financial statements include costs that have been incurred by the Company and then directly billed or allocated to affiliates, and costs that have been incurred by our affiliates and then directly billed or allocated to us, and are recorded net in general and administrative expense on the consolidated statements of operations with a corresponding accounts receivable—affiliates or accounts payable—affiliates, respectively, recorded in the consolidated balance sheets. Additionally, the Company enters into transactions with certain affiliates for sales or purchases of natural gas and electricity, which are recorded in retail revenues, retail cost of revenues, and net asset optimization revenues in the consolidated statements of operations with a corresponding accounts receivable—affiliate or accounts payable—affiliate in the consolidated balance sheets. The allocations and related estimates and assumptions are described more fully in Note 15 "Transactions with Affiliates."

Cash and Cash Equivalents

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. The Company periodically assesses the financial condition of the institutions where these funds are held and believes that its credit risk is minimal with respect to these institutions.

Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest.

The Company accrues an allowance for doubtful accounts based upon estimated uncollectible accounts receivable considering historical collections, accounts receivable aging analysis, credit risk and other factors. The Company writes off accounts receivable balances against the allowance for doubtful accounts when the accounts receivable is deemed to be uncollectible. Bad debt expense of $13.5 million, $10.1 million and $6.6 million was recorded in general and administrative expense in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, respectively.

The Company conducts business in many utility service markets where the local regulated utility purchases our receivables, and then becomes responsible for billing the customer and collecting payment from the customer (“POR programs”). This POR service results in substantially all of the Company’s credit risk being linked to the applicable utility, which generally has an investment-grade rating, and not to the end-use customer. The Company monitors the financial condition of each utility and currently believes such amounts are collectible. Trade accounts receivable that are part of a local regulated utility’s POR program are recorded on a gross basis in accounts receivable in the consolidated balance sheets. The discount paid to the local regulated utilities is recorded in general and administrative expense in the consolidated statements of operations.

In markets that do not offer POR services or when the Company chooses to directly bill its customers, certain receivables are billed and collected by the Company. The Company bears the credit risk on these accounts and records an appropriate allowance for doubtful accounts to reflect any losses due to non-payment by customers. The Company’s customers are individually insignificant and geographically dispersed in these markets. The Company writes off customer balances when it believes that amounts are no longer collectible and when it has exhausted all means to collect these receivables.

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Inventory

Inventory consists of natural gas used to fulfill and manage seasonality for fixed and variable-price retail customer load requirements and is valued at the lower of weighted average cost or net realizable value. Purchased natural gas costs are recognized in the consolidated statements of operations, within retail cost of revenues, when the natural gas is sold and delivered out of the storage facility using the weighted average cost of the gas sold.

Customer Acquisition Costs

The Company capitalizes direct response advertising costs that consist primarily of hourly and commission-based telemarketing costs, door-to-door agent commissions and other direct advertising costs associated with proven customer generation in its balance sheet. These costs are amortized over the estimated life of a customer.

As of December 31, 2019 and 2018, the net customer acquisition costs were $18.5 million and $18.3 million, respectively, of which $8.7 million and $14.4 million were recorded in current assets, and $9.8 million and $3.9 million were recorded in non-current assets. Amortization of customer acquisition costs was $18.5 million, $24.4 million, and $21.4 million for the years ended December 31, 2019, 2018 and 2017, respectively. Customer acquisition costs do not include customer acquisitions through merger and acquisition activities, which are recorded as customer relationships.

Recoverability of customer acquisition costs is evaluated based on a comparison of the carrying amount of such costs to the future net cash flows expected to be generated by the customers acquired, considering specific assumptions for customer attrition, per unit gross profit, and operating costs. These assumptions are based on forecasts and historical experience.

Customer Relationships

Customer contracts recorded as part of mergers or acquisitions are reflected as customer relationships in our balance sheet. The Company had capitalized customer relationship of $13.6 million and $16.6 million, net of amortization, as current assets as of December 31, 2019 and 2018, respectively, and $17.8 million and $26.4 million, net of amortization, as non-current assets as of December 31, 2019 and 2018, respectively, related to these intangible assets. These intangibles are amortized on a straight-line basis over the estimated average life of the related customer contracts acquired, which ranges from three to six years.

The acquired customer relationships intangibles related to Oasis, CenStar, Provider Companies, Major Energy Companies, Perigee Energy LLC, Verde Companies, and HIKO are reflective of the acquired companies’ customer base, and were valued at the respective dates of acquisition using an excess earnings method under the income approach. Using this method, the Company estimated the future cash flows resulting from the existing customer relationships, considering attrition as well as charges for contributory assets, such as net working capital, fixed assets, and assembled workforce. These future cash flows were then discounted using an appropriate risk-adjusted rate of return by retail unit to arrive at the present value of the expected future cash flows. CenStar, Oasis, Perigee, and HIKO customer relationships are amortized to depreciation and amortization based on the expected future net cash flows by year. The acquired customer relationship intangibles related to the Major Energy Companies, the Provider Companies and the Verde Companies were bifurcated between hedged and unhedged and amortized to depreciation and amortization based on the expected future cash flows by year and expensed to retail cost of revenue based on the expected term of the underlying fixed price contract in each reporting period, respectively.

Customer relationship amortization expense was $18.3 million, $20.3 million, and $17.8 million for the years ended December 31, 2019, 2018 and 2017, respectively, of which approximately less than $0.1 million, $(1.2) million, and $0.3 million was included in retail cost of revenue for those years.

We review customer relationships for impairment whenever events or changes in business circumstances indicate the carrying value of the intangible assets may not be recoverable. Impairment is indicated when the undiscounted

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cash flows estimated to be generated by the intangible assets are less than their respective carrying value. If an impairment exists, a loss is recognized for the difference between the fair value and carrying value of the intangible assets. No impairments of customer relationships were recorded for the years ended December 31, 2019, 2018 and 2017.

Non-compete agreements

We capitalize intangible costs associated with non-compete agreements in certain of our acquisitions. Non-compete agreements provide the Company with a certain level of assurance that acquired companies' expected earnings streams will not be disrupted by competition from the companies’ previous owners or members. These non-compete agreements are amortized over their estimated useful life of three years on a straight-line basis. As of December 31, 2019, the Company had zero capitalized costs related to these non-compete agreements. As of December 31, 2018, the Company had $0.3 million of capitalized costs related to non-compete agreements, of which $0.3 million was current, and of which zero was non-current. Amortization expense was $0.3 million, $1.1 million and $1.2 million for the years ended December 31, 2019, 2018 and 2017.

Trademarks

We record trademarks as part of our acquisitions which represent the value associated with the recognition and positive reputation of an acquired company to its target markets. This value would otherwise have to be internally developed through significant time and expense or by paying a third party for its use. These intangibles are amortized over the estimated five-year to ten-year life of the trademark on a straight-line basis. The fair values of trademark assets were determined at the date of acquisition using a royalty savings method under the income approach. Under this approach, the Company estimates the present value of expected cash flows resulting from avoiding royalty payments to use a third party trademark. The Company analyzes market royalty rates charged for licensing trademarks and applied an expected royalty rate to a forecast of estimated revenue, which was then discounted using an appropriate risk adjusted rate of return. As of December 31, 2019 and 2018, we had recorded $5.7 million and $7.3 million related to these trademarks in other assets. Amortization expense was $1.6 million, $1.3 million, and $0.8 million for the years ended December 31, 2019, 2018 and 2017, respectively.

We review trademarks for impairment whenever events or changes in business circumstances indicate the carrying value of the intangible assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by the intangible assets are less than their respective carrying value. If an impairment exists, a loss is recognized for the difference between the fair value and carrying value of the intangible assets. No impairments of trademarks were recorded for the years ended December 31, 2019, 2018 and 2017.

Operating Leases

The Company's leases consist of operating leases related to our offices with lease terms expiring through 2022. The initial term for our property leases is typically three to five years, with renewal options. Rent is recognized on a straight-line basis over the lease term. We adopted ASU 2016-02 effective January 1, 2019, and recorded right-of-use assets and liabilities for our operating leases of $1.0 million.

For our operating leases, we recorded rent expense of $0.8 million, $0.8 million and $0.6 million for the years ended December 31, 2019, 2018 and 2017, respectively. We recorded sub-lease income of $0.4 million, zero and zero for the years ended December 31, 2019, 2018 and 2017, respectively. As of December 31, 2019 we had recorded right-of-use asset of $0.4 million in other current assets and other assets. As of December 31, 2019 we had recorded lease liability of $0.6 million in other current liabilities and other long-term liabilities.

Deferred Financing Costs

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Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense using the straight-line method over the life of the related long-term debt. These costs are included in other assets in our consolidated balance sheets.

Property and Equipment

The Company records property and equipment at historical cost. Depreciation expense is recorded on a straight-line method based on estimated useful lives, which range from 2 to 5 years, along with estimates of the salvage values of the assets. When items of property and equipment are sold or otherwise disposed of, any gain or loss is recorded in the consolidated statements of operations.

The Company capitalizes costs associated with certain of its internal-use software projects. Costs capitalized are those incurred during the application development stage of projects such as software configuration, coding, installation of hardware and testing. Costs incurred during the preliminary or post-implementation stage of the project are expensed in the period incurred, including costs associated with formulation of ideas and alternatives, training and application maintenance. After internal-use software projects are completed, the associated capitalized costs are depreciated over the estimated useful life of the related asset. Interest costs incurred while developing internal-use software projects are also capitalized. Capitalized interest costs for the years ended December 31, 2019, 2018 and 2017 were not material.

Goodwill

Goodwill represents the excess of cost over fair value of the assets of businesses acquired in accordance with FASB ASC Topic 350 Intangibles-Goodwill and Other ("ASC 350"). The goodwill on our consolidated balance sheet as of December 31, 2019 is associated with both our Retail Natural Gas and Retail Electricity segments. We determine our segments, which are also considered our reporting unit, by identifying each unit that engaged in business activities from which it may earn revenues and incur expenses, had operating results regularly reviewed by the segment manager for purposes of resource allocation and performance assessment, and had discrete financial information.

Goodwill is not amortized, but rather is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually as of October 31. We compare our estimate of the fair value of the reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, we would recognize a goodwill impairment loss for the amount by which the reporting unit's carrying value exceeds its fair value. In accordance with our accounting policy, we completed our annual assessment of goodwill impairment as of October 31, 2019 during the fourth quarter of 2019, using a qualitative assessment approach, and the test indicated no impairment.

Treasury Stock

Treasury stock consists of Company's own stock that has been issued, but subsequently reacquired by the Company. Treasury stock does not reduce the number of shares issued but does reduce the number of shares outstanding. These shares are not eligible to receive cash dividends. We use the cost method to account for treasury shares.

Equity Method Investments

We use the equity method of accounting to account for investments where we have the ability to exercise significant influence, but not control over, the investee. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and our share of earnings or losses and distributions. Prior to the sale of our equity investment in November 2019, our equity investment was presented on the consolidated balance sheet under "Other assets", with our share of their income reflected as "Total other income/(expense)" on the consolidated statements of operations. We determined our equity investment earnings using the Hypothetical Liquidation at Book Value (HLBV) method. Under the HLBV method, a calculation was prepared at

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each balance sheet date to determine the amount the Company would receive if the investee were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is the Company's share of the earnings or losses from the equity investment for the period. See Note 17 "Equity Method Investment" for further discussion.

Revenues and Cost of Revenues

Our revenues are derived primarily from the sale of natural gas and electricity to customers, including affiliates. Revenues are recognized by the Company based on consideration specified in contracts with customers when performance obligations are satisfied by transferring control over products to a customer . Utilizing these criteria, revenue is recognized when the natural gas or electricity is delivered to the customer. Similarly, cost of revenues is recognized when the commodity is delivered.

Revenues for natural gas and electricity sales are recognized under the accrual method. Natural gas and electricity sales that have been delivered but not billed by period end are estimated. Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class. Estimated amounts are adjusted when actual usage is known and billed.

Costs for natural gas and electricity sales are similarly recognized under the accrual method. Natural gas and electricity costs that have not been billed to the Company by suppliers but have been incurred by period end are estimated. The Company estimates volumes for natural gas and electricity delivered based on the forecasted revenue volumes, estimated transportation cost volumes and estimation of other costs associated with retail load that varies by commodity utility territory. These costs include items like ISO fees, ancillary services and renewable energy credits. Estimated amounts are adjusted when actual usage is known and billed.

Our asset optimization activities, which primarily include natural gas physical arbitrage and other short term storage and transportation transactions, meet the definition of trading activities and are recorded on a net basis in the consolidated statements of operations in net asset optimization revenues. The Company recorded asset optimization revenues, primarily related to physical sales or purchases of commodities, of $62.8 million, $113.7 million and $178.3 million for the years ended December 31, 2019, 2018 and 2017, respectively, and recorded asset optimization costs of revenues of $60.0 million, $109.2 million and $179.0 million for the years ended December 31, 2019, 2018 and 2017, respectively, which are presented on a net basis in asset optimization revenues.

Natural Gas Imbalances

The consolidated balance sheets include natural gas imbalance receivables and payables, which primarily result when customers consume more or less gas than has been delivered by the Company to local distribution companies (“LDCs”). The settlement of natural gas imbalances varies by LDC, but typically the natural gas imbalances are settled in cash or in kind on a monthly, quarterly, semi-annual or annual basis. The imbalances are valued at their estimated net realizable value. The Company recorded an imbalance receivable of $1.6 million and $0.8 million in other current assets on the consolidated balance sheets as of December 31, 2019 and 2018, respectively. The Company recorded an imbalance payable of $0.1 million and $0.3 million in other current liabilities on the consolidated balance sheets as of December 31, 2019 and 2018, respectively.

Derivative Instruments

The Company uses derivative instruments such as futures, swaps, forwards and options to manage the commodity price risks of its business operations.

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All derivatives are recorded in the consolidated balance sheets at fair value. Derivative instruments representing unrealized gains are reported as derivative assets while derivative instruments representing unrealized losses are reported as derivative liabilities. We offset amounts in the consolidated balance sheets for derivative instruments executed with the same counterparty where we have a master netting arrangement.

As part of our asset optimization activities, we manage a portfolio of commodity derivative instruments held for trading purposes. Changes in fair value of and amounts realized upon settlements of derivatives instruments held for trading purposes are recognized in earnings in net asset optimization revenues.

To manage the retail business, the Company holds derivative instruments that are not for trading purposes and are not designated as hedges for accounting purposes. Changes in the fair value of and amounts realized upon settlement of derivative instruments not held for trading purposes are recognized in retail costs of revenues.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes where deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in the financial statements or tax returns and operating loss carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in those years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be realized. Amounts owed or refundable on current year returns is included as a current payable or receivable in the consolidated balance sheet.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the projected future taxable income and tax planning strategies in making this assessment.

The Company recognizes interest and penalties related to unrecognized tax benefits within the provision for income taxes on continuing operations in our consolidated statements of operations.

Earnings per Share

Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interests. Diluted earnings per share is similarly calculated except that the denominator is increased by potentially dilutive securities. We use the treasury stock method to determine the potential dilutive effect of our outstanding unvested restricted stock units and use the if-converted method to determine the potential dilutive effect of our Class B common stock.

Non-controlling Interest

Net income attributable to non-controlling interest represents the Class B Common stockholders' interest in income and expenses of the Company. The weighted average ownership percentages for the applicable reporting period are used to allocate the income (loss) before income taxes to each economic interest owner.

Commitments and Contingencies

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Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

Recent Accounting Pronouncements

In January 2017, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ("ASU 2017-04"). ASU 2017-04 simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under this update, an entity should perform its annual or interim goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount, including goodwill. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 should be applied on a prospective basis and is effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. We adopted ASU 2017-04 effective January 1, 2019, and the adoption of this standard did not have a material impact on the Company's consolidated financial statements.

In June 2018, the FASB issued ASU No. 2018-07, Compensation - Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting ("ASU 2018-07"). ASU 2018-07 primarily expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. ASU 2018-07 is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. We adopted ASU 2018-07 effective January 1, 2019, and the adoption of this standard did not have a material impact on the Company's consolidated financial statements.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) ("ASU 2016-02"). Under this new guidance, lessees are required to recognize assets and liabilities on the balance sheet for the rights and obligations created by all leases with terms of greater than twelve months. The guidance requires qualitative disclosures along with certain specific quantitative disclosures for both lessees and lessors. The FASB issued ASU No. 2018-10, Codification Improvements to Topic 842, Leases, ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, and ASU No. 2019-01, Leases (Topic 842): Codification Improvements, to provide additional guidance for the adoption of Topic 842. ASU 2016-02 and its related amendments are effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and are effective for interim periods in the year of adoption. ASU 2016-02 should be applied using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented with an option to use certain practical expedients, which we elected to use. We evaluated the impact of this new guidance and reviewed lease or possible lease contracts and evaluated contract related processes. We adopted ASU 2016-02 effective January 1, 2019 and recorded right-of-use assets and liabilities for our real estate operating leases of approximately $1.0 million.

Standards Being Evaluated/Standards Not Yet Adopted

Below are accounting standards that have been issued, but not yet been adopted by the Company at December 31, 2019. The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial statements.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ("ASU 2016-13"). ASU 2016-13 requires entities to use a current expected credit loss ("CECL") model, which is a new impairment model based on expected losses rather than incurred losses on financial assets, including trade accounts receivables. The model requires financial assets measured at amortized cost to be presented at the net amount expected to be collected. ASU 2016-13 is effective for

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fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. We adopted ASU 2016-13 and related amendments effective January 1, 2020, and the adoption did not have a material impact on our consolidated financial statements.

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740), Simplifying the Accounting for Income Taxes ("ASU 2019-12"). These amendments simplify the accounting for income taxes by removing certain exceptions to the general principles in Topic 740. For public business entities, the amendments in this Update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. We do not expect adoption of the new standard to have a material impact to our consolidated statement of operations.

3. Revenues

Our revenues are derived primarily from the sale of natural gas and electricity to customers, including affiliates. Revenue is measured based upon the quantity of gas or power delivered at prices contained or referenced in the customer's contract, and excludes any sales incentives (e.g. rebates) and amounts collected on behalf of third parties (e.g. sales tax).

Our revenues also include asset optimization activities. Asset optimization activities consist primarily of purchases and sales of gas that meet the definition of trading activities per FASB ASC Topic 815, Derivatives and Hedging. They are therefore excluded from the scope of FASB ASC Topic 606, Revenue from Contracts with Customers.

Revenues for electricity and natural gas sales are recognized under the accrual method when our performance obligation to a customer is satisfied, which is the point in time when the product is delivered and control of the product passes to the customer. Electricity and natural gas products may be sold as fixed-price or variable-price products. The typical length of a contract to provide electricity and/or natural gas is 12 months. Customers are billed and typically pay at least monthly, based on usage. Electricity and natural gas sales that have been delivered but not billed by period end are estimated and recorded as accrued unbilled revenues based on estimates of customer usage since the date of the last meter read provided by the utility. Volume estimates are based on forecasted volumes and estimated residential and commercial customer usage. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate by customer class (residential or commercial). Estimated amounts are adjusted when actual usage is known and billed.

The following table discloses revenue by primary geographical market, customer type, and customer credit risk profile (in thousands). The table also includes a reconciliation of the disaggregated revenue to revenue by reportable segment (in thousands).

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Reportable Segments
	Year Ended December 31, 2019										Year Ended December 31, 2018										Year Ended December 31, 2017
	Retail Electricity			Retail Natural Gas			Total Reportable Segments				Retail Electricity			Retail Natural Gas			Total Reportable Segments				Retail Electricity			Retail Natural Gas			Total Reportable Segments
Primary markets (a)
New England	$	284,909		$	19,289		$	304,198			$	395,682		$	21,221		$	416,903			$	229,546		$	21,196		$	250,742
Mid-Atlantic	242,556			42,469			285,025				291,046			54,815			345,861				272,127			52,737			324,864
Midwest	79,188			39,200			118,388				73,167			39,894			113,061				59,506			37,792			97,298
Southwest	81,798			21,545			103,343				103,556			22,036			125,592				96,387			29,481			125,868
	$	688,451		$	122,503		$	810,954			$	863,451		$	137,966		$	1,001,417			$	657,566		$	141,206		$	798,772
Customer type
Commercial	$	249,730		$	40,466		$	290,196			$	355,607		$	50,156		$	405,763			$	195,356		$	50,424		$	245,780
Residential	449,900			83,455			533,355				518,261			93,186			611,447				441,580			89,889			531,469
Unbilled revenue (b)	(11,179		)	(1,418		)	(12,597		)		(10,417		)	(5,376		)	(15,793		)		20,630			893			21,523
	$	688,451		$	122,503		$	810,954			$	863,451		$	137,966		$	1,001,417			$	657,566		$	141,206		$	798,772
Customer credit risk
POR	$	479,011		$	64,416		$	543,427			$	586,901		$	71,565		$	658,466			$	447,581		$	76,002		$	523,583
Non-POR	209,440			58,087			267,527				276,550			66,401			342,951				209,985			65,204			275,189
	$	688,451		$	122,503		$	810,954			$	863,451		$	137,966		$	1,001,417			$	657,566		$	141,206		$	798,772

(a) The primary markets include the following states:

•	New England - Connecticut, Maine, Massachusetts, New Hampshire;

•	Mid-Atlantic - Delaware, Maryland (including the District of Colombia), New Jersey, New York and Pennsylvania;

•	Midwest - Illinois, Indiana, Michigan and Ohio; and

•	Southwest - Arizona, California, Colorado, Florida, Nevada, and Texas.

(b) Unbilled revenue is recorded in total until it is actualized, at which time it is categorized between commercial and residential customers.

We record gross receipts taxes on a gross basis in retail revenues and retail cost of revenues. During the year ended December 31, 2019, 2018 and 2017 our retail revenues included gross receipts taxes of $1.5 million, $1.6 million and $6.4 million respectively. During the year ended December 31, 2019, 2018 and 2017, our retail cost of revenues included gross receipts taxes of $8.4 million, $9.9 million and $9.0 million, respectively.

4. Acquisitions

Acquisition of Perigee

In April 2017, we acquired all of the outstanding membership interests of Perigee Energy, LLC, a Texas limited liability company ("Perigee"), with operations across 14 utilities in Connecticut, Delaware, Massachusetts, New York and Ohio from our affiliate, NG&E. The purchase price for Perigee from NG&E was approximately $4.1 million, which consisted of a base price of $2.0 million, $0.2 million additional customer option payment, and $1.9 million in working capital, subject to adjustments. The acquisition was treated as a transfer of equity interests

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between entities under common control, and accordingly, the assets acquired and liabilities assumed were based on their historical value as of the date. NG&E acquired Perigee, which was on February 3, 2017, and the fair value of the net assets acquired was as follows (in thousands):

	Final Purchase Price Allocation
Cash	$	23
Intangible assets—customer relationships	1,100
Goodwill	1,540
Net working capital, net of cash acquired	2,085
Fair value of derivative liabilities	(443		)
Total	$	4,305

The Perigee acquisition did not have a material impact on our financial position or results of operations.

Acquisition of Verde

In July 2017, we acquired, through our subsidiary CenStar Energy Corp. ("CenStar"), all of the outstanding membership interests and stock in a group of companies (the "Verde Companies") from Verde Energy USA Holdings, LLC (the “Seller”). Total consideration was approximately $90.7 million, of which $20.1 million represented positive net working capital, as adjusted. We also entered into an agreement to pay an additional amount based on achievement by the Verde Companies of certain performance targets over the 18 month period following closing of the acquisition (the "Verde Earnout"). The Verde Earnout was initially valued at $5.4 million. The acquisition of the Verde Companies was accounted for under the acquisition method. The allocation of purchase consideration was based upon the estimated fair value of the tangible and identifiable intangible assets acquired and liabilities assumed in the acquisition based on management's best estimates, and was supported by independent third-party analyses. The excess of the purchase price over the estimated fair value of tangible and intangible assets acquired and liabilities assumed was allocated to goodwill. The allocation of the purchase consideration was as follows (in thousands):

	Final Purchase Price Allocation as of December 31, 2018
Cash and restricted cash	$	1,653
Property and equipment	4,560
Intangible assets—customer relationships	28,700
Intangible assets—trademarks	3,000
Goodwill	39,396
Net working capital, net of cash acquired	18,473
Deferred tax liability	(3,126		)
Fair value of derivative liabilities	(1,942		)
Total	$	90,714

The Verde Earnout was based on achievement by the Verde Companies of certain performance targets over the 18 month period following the closing of the Verde acquisition. In January 2018, we settled the Verde Earnout by issuing a $5.9 million note payable to the Seller. See Note 10 "Debt" for further discussion.

The Verde Companies contributed revenues of $76.0 million and earnings of $1.2 million to the Company for the year ended December 31, 2017.

Acquisition of HIKO

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In March 2018, we entered into a Membership Interest Purchase Agreement under which we acquired all of the membership interests of HIKO Energy, LLC ("HIKO"), a New York limited liability company, for a total purchase price of $6.0 million in cash, plus working capital. At the time of acquisition, HIKO had a total of approximately 29,000 RCEs located in 42 markets in seven states. The acquisition was accounted for under the acquisition method. Our preliminary allocation of the purchase price was based upon the estimated fair value of the tangible and identified intangible assets acquired and liabilities assumed in the acquisition. The allocation of the purchase consideration is as follows (in thousands):

	Final Purchase Price Allocation as of December 31, 2018
Cash and restricted cash	$	375
Intangible assets—customer relationships	6,031
Net working capital, net of cash acquired	8,465
Fair value of derivative liabilities	(205		)
Total	$	14,666

Our consolidated statements of operations for the twelve months ended December 31, 2018 included $15.3 million of revenue and $3.8 million of net income related to the operations of HIKO.

In each of our acquisitions, we evaluate and allocate purchase price based on the following general assumptions.

Customer relationships. Acquired customer relationships were reflective of the acquired companies' customer bases, and were valued using an excess earnings method under the income approach. Using this method, we estimated the future cash flows resulting from the existing customer relationships, considering estimated attrition as well as charges for contributory assets, such as net working capital, intangible assets, fixed assets, and any assembled workforce. These future cash flows were then discounted using an appropriate risk-adjusted rate of return to arrive at the present value of the expected future cash flows.

In acquisitions where we acquired commodity contracts that we could match to fixed-price contracts, customer relationships were bifurcated between unhedged and hedged and are being amortized based on the expected term of the underlying fixed-price contract acquired in each reporting period, respectively.

Non-compete Agreements. The fair value of non-compete agreements were determined using the differential value approach. Under this approach, we estimated the present value of expected future cash flows of the business with and without the non-compete agreement. The difference in discounted cash flows was then adjusted by probability factors related to the likelihood that those with the non-compete agreements would be successful competitors.

Trademarks. The fair value of acquired trademarks is reflective of the value associated with the recognition and reputation of the acquired company to target markets. The fair value of trademarks was valued using a royalty savings method under the income approach. The value was based on the savings we would realize from owning the trademark rather than paying a royalty for the use of that trademark. Under this approach, we estimate the present value of the expected cash flows resulting from avoiding royalty payments to use a third party trademark. In the Verde acquisition, we analyzed market royalty rates charged for licensing trademarks and applied an expected royalty rate to a forecast of estimated revenue, which was then discounted using an appropriate risk adjusted rate of return.

Goodwill. The excess of the purchase consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill arose on the acquisitions of the Provider Companies, Verde Companies and Perigee primarily due to the value of their assembled workforce, proprietary sales channels, and/or access to new utility service territories. Goodwill arose on the acquisition of the Major Energy Companies primarily due to the value of the Major Energy Companies brand strength, established

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vendor relationships and access to new utility service territories. Goodwill recorded in connection with these acquisitions is deductible for income tax purposes because these were acquisitions of all of the assets of the companies.

Customer Acquisitions. We also, from time to time, acquire books of customers from affiliated and non-affiliated parties. These acquisitions do not involve an allocation of the purchase price but rather are recorded as customer relationships.

Acquisition of customers from Perigee

In April 2017, we acquired approximately 44,000 RCEs from the original owner of Perigee. During 2017, we paid $7.5 million for customers transferred.

Acquisition from Related Parties

In March 2018, we entered into an asset purchase agreement with an affiliate pursuant to which we agreed to acquire up to 50,000 RCEs for a cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate. These customers began transferring after April 1, 2018 and are located in 24 markets in 8 states. For the year ended December 31, 2018, we paid $8.8 million under the terms of the purchase agreement for approximately 35,000 RCEs. No additional customer transfers or consideration will be paid on this transaction. The acquisition was treated as a transfer of assets between entities under common control, and accordingly, the assets were recorded at our affiliate's historical value at the date of transfer, which was $1.7 million. The transaction resulted in $7.1 million recorded in equity as a net distribution to affiliate as of December 31, 2018. Of the $8.8 million paid to our affiliate, $1.7 million was an investing cash outflow, and the remaining $7.1 million was deemed a distribution to our non-controlling interest and classified as financing activity.

Acquisitions of Customer Books

In October 2018, we entered into an asset purchase agreement pursuant to which we agreed to acquire up to 60,000 RCEs from Starion Energy Inc., Starion Energy NY Inc. and Starion Energy PA Inc. (collectively "Starion") for a cash purchase price of up to a maximum of $10.7 million. These customers began transferring in December 2018, and are located in our existing markets. As of December 31, 2019, a total of $8.0 million was paid under the terms of the purchase agreement for approximately 51,000 RCEs.

As part of the acquisition, we funded an escrow account, the balance of which is reflected as restricted cash in our consolidated balance sheet. As of December 31, 2019 and 2018, the balance in the escrow account was $1.0 million and $8.6 million, respectively. The balance remaining as of December 31, 2019 represents a holdback of amounts due to the seller for acquired customers that will be released to the seller in April 2020, subject to certain adjustments outlined in the asset purchase agreement.

5. Equity

Non-controlling Interest

We hold an economic interest and are the sole managing member in Spark HoldCo, with affiliates of our Founder and majority shareholder holding the remaining economic interests in Spark HoldCo. As a result, we consolidate the financial position and results of operations of Spark HoldCo, and reflect the economic interests owned by these affiliates as a non-controlling interest. The Company and affiliates owned the following economic interests in Spark HoldCo at December 31, 2019 and December 31, 2018, respectively.

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	The Company		Affiliated Owners
December 31, 2019	41.04	%	58.96	%
December 31, 2018	40.53	%	59.47	%

The following table summarizes the portion of net income (loss) and income tax expense (benefit) attributable to non-controlling interest (in thousands):

	Year Ended December 31,
	2019			2018			2017
Net income (loss) allocated to non-controlling interest	$	7,604		$	(12,140	)	$	55,068
Income tax expense (benefit) allocated to non-controlling interest	1,841			1,066			(731		)
Net income (loss) attributable to non-controlling interest	$	5,763		$	(13,206	)	$	55,799

Class A Common Stock and Class B Common Stock

Holders of the Company's Class A common stock and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by our certificate of incorporation.

Dividends on Class A Common Stock

Dividends declared for the Company's Class A common stock are reported as a reduction of retained earnings, or a reduction of additional paid in capital to the extent retained earnings are exhausted. During the years ended December 31, 2019, 2018, and 2017, we paid dividends on our Class A Common Stock of $10.4 million, $9.8 million, and $9.5 million. This dividend represented an annual rate of $0.725 per share on each share of Class A common stock.

On January 21, 2020, the Company declared a dividend of $0.18125 per share to holders of record of our Class A common stock on March 2, 2020 and payable on March 16, 2020.

In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of its units, including those holders that own our Class B common stock (our non-controlling interest holder). As a result, during the year ended December 31, 2019, Spark HoldCo made corresponding distributions of $15.1 million to our non-controlling interest holders.

Stock Split

In May 2017, the Company authorized and approved a two-for-one stock split of the Company's issued Class A common stock and Class B common stock, which was effected through a stock dividend (the "Stock Split"). Shareholders of record at the close of business on June 5, 2017 were issued one additional share of Class A common stock or Class B common stock of the Company for each share of Class A common stock or Class B common stock, respectively, held by such shareholder on that date. Such additional shares of Class A common stock or Class B common stock were distributed on June 16, 2017. All shares and per share amounts in this report have been retrospectively restated to reflect the Stock Split.

Preferred Stock

The Company has 20,000,000 shares of authorized preferred stock for which there are 3,707,256 shares issued and 3,677,318 shares outstanding at December 31, 2019 and 3,707,256 issued and outstanding shares at December 31, 2018. See Note 6 "Preferred Stock" for a further discussion of preferred stock.

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Issuance of Class A Common Stock Upon Vesting of Restricted Stock Units

For the years ended December 31, 2019, 2018, and 2017, 473,492, 394,243, and 356,014, respectively of restricted stock units vested, with 300,715, 258,076, and 241,965, respectively of shares of common stock distributed to the holders of these units. Differences between shares vested and issued were a result of 172,777, 136,167, and 114,049 shares of common stock withheld by the Company to cover taxes owed on the vesting of such units.

Conversion of Class B Common Stock to Class A Common Stock

In 2018, holders of Class B common stock exchanged 685,126 of their Spark HoldCo units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock at an exchange ratio of one share of Class A common stock for each Spark HoldCo unit (and corresponding share of Class B common stock) exchanged.

Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income attributable to stockholders (the numerator) by the weighted-average number of Class A common shares outstanding for the period (the denominator). Class B common shares are not included in the calculation of basic earnings per share because they are not participating securities and have no economic interests. Diluted earnings per share is similarly calculated except that the denominator is increased by potentially dilutive securities.

The following table presents the computation of basic and diluted income (loss) per share for the years ended December 31, 2019, 2018, and 2017 (in thousands, except per share data):

	Year Ended December 31,
	2019			2018			2017
Net income (loss) attributable to Spark Energy, Inc. stockholders	$	8,450		$	(1,186	)	$	19,245
Less: Dividend on Series A preferred stock	8,091			8,109			3,038
Net income (loss) attributable to stockholders of Class A common stock	$	359		$	(9,295	)	$	16,207
Basic weighted average Class A common shares outstanding	14,286			13,390			13,143
Basic earnings (loss) per share attributable to stockholders	$	0.03		$	(0.69	)	$	1.23
Net income (loss) attributable to stockholders of Class A common stock	$	359		$	(9,295	)	$	16,207
Effect of conversion of Class B common stock to shares of Class A common stock	—			—			—
Diluted net income (loss) attributable to stockholders of Class A common stock	$	359		$	(9,295	)	$	16,207
Basic weighted average Class A common shares outstanding	14,286			13,390			13,143
Effect of dilutive Class B common stock	—			—			—
Effect of dilutive restricted stock units	282			—			203
Diluted weighted average shares outstanding	14,568			13,390			13,346
Diluted earnings (loss) per share attributable to stockholders	$	0.02		$	(0.69	)	$	1.21

The computation of diluted earnings per share for the year ended December 31, 2019 excludes 20.8 million shares of Class B common stock because the effect of their conversion was antidilutive. The Company's outstanding shares

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of Series A Preferred Stock were not included in the calculation of diluted earnings per share because they contain only contingent redemption provisions that have not occurred.

Variable Interest Entity

Spark HoldCo is a variable interest entity due to its lack of rights to participate in significant financial and operating decisions and its inability to dissolve or otherwise remove its management. Spark HoldCo owns all of the outstanding membership interests in each of our operating subsidiaries. We are the sole managing member of Spark HoldCo, manage Spark HoldCo's operating subsidiaries through this managing membership interest, and are considered the primary beneficiary of Spark HoldCo. The assets of Spark HoldCo cannot be used to settle our obligations except through distributions to us, and the liabilities of Spark HoldCo cannot be settled by us except through contributions to Spark HoldCo. The following table includes the carrying amounts and classification of the assets and liabilities of Spark HoldCo that are included in our consolidated balance sheet as of December 31, 2019 and 2018 (in thousands):

	December 31, 2019			December 31, 2018
Assets
Current assets:
Cash and cash equivalents	$	56,598		$	36,724
Accounts receivable	113,635			150,866
Other current assets	64,476			92,963
Total current assets	234,709			280,553
Non-current assets:
Goodwill	120,343			120,343
Other assets	37,826			47,159
Total non-current assets	158,169			167,502
Total Assets	$	392,878		$	448,055
Liabilities
Current liabilities:
Accounts Payable and Accrued Liabilities	$	86,097		$	79,692
Contingent consideration	—			1,328
Other current liabilities	65,863			59,330
Total current liabilities	151,960			140,350
Long-term liabilities:
Long-term portion of Senior Credit Facility	123,000			129,500
Subordinated debt—affiliate	—			10,000
Other long-term liabilities	712			319
Total long-term liabilities	123,712			139,819
Total Liabilities	$	275,672		$	280,169

6. Preferred Stock

In March 2017, we issued 1,610,000 shares of 8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock ("Series A Preferred Stock"), par value $0.01 per share and having a liquidation preference $25.00 per share, plus accumulated and unpaid dividends, at a price to the public of $25.00 per share ($24.21 per share to us, net of underwriting discounts and commissions). We received approximately $39.0 million in net proceeds from the offering, after deducting underwriting discounts and commissions and a structuring fee. Offering expenses of $1.0 million were recorded as a reduction to the carrying value of the Series A Preferred Stock.

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In July 2017, we entered into an At-the-Market Issuance Sales Agreement ("the ATM Agreement") with FBR Capital Markets & Co. as sales agent (the "Agent"). Pursuant to the terms of the ATM Agreement, we may sell, from time to time through the Agent, our Series A Preferred Stock, having an aggregate offering price of up to $50.0 million. During the year ended December 31, 2017, we issued an aggregate of 94,339 shares of Series A Preferred Stock under the ATM Agreement. We received net proceeds of $2.4 million and paid compensation to the sales agent of less than $0.1 million with respect to these sales. During the year ended December 31, 2018, we issued an aggregate of 2,917 shares of Series A Preferred Stock under the ATM Agreement. We received net proceeds of $0.1 million and paid compensation to the sales agent of less than $0.1 million with respect to these sales.

In January 2018, we issued 2,000,000 shares of Series A Preferred Stock, plus accumulated and unpaid dividends, at a price to the public of $25.25 per share. The Company received approximately $48.9 million ($24.45 per share) in net proceeds from the offering, after deducting underwriting discounts and commissions and a structuring fee. Offering expenses of $0.5 million were recorded as a reduction to the carrying value of the Series A Preferred Stock.

In May 2019, we commenced a share repurchase program (the "Repurchase Program") of our Series A Preferred Stock. We may make purchases of our Series A Preferred Stock under the Repurchase Program through May 20, 2020, and there is no dollar limit on the amount of Series A Preferred Stock that may be repurchased, nor does the Repurchase Program obligate the Company to make any repurchases.

In November 2019, we amended and extended our repurchase program (the "Repurchase Program") of our Series A Preferred Stock. The Repurchase Program allows us to purchase Preferred Stock through December 31, 2020, at prevailing prices, in open market or negotiated transactions, subject to market conditions, maximum share prices and other considerations. The Repurchase Program does not obligate us to make any repurchases and may be suspended at any time.

During the year ended December 31, 2019, we repurchased 29,938 shares of Series A Preferred Stock at a weighted-average price of $24.82 per share, for a total cost of approximately $0.7 million.

Holders of the Series A Preferred Stock have no voting rights, except in specific circumstances of delisting or in the case the dividends are in arrears as specified in the Series A Preferred Stock Certificate of Designations. The Series A Preferred Stock accrue dividends at an annual percentage rate of 8.75%, and the liquidation preference provisions of the Series A Preferred Stock are considered contingent redemption provisions because there are rights granted to the holders of the Series A Preferred Stock that are not solely within our control upon a change in control of the Company. Accordingly, the Series A Preferred Stock is presented between liabilities and the equity sections in the accompanying consolidated balance sheet.

During the year ended December 31, 2019, we paid $8.1 million in dividends to holders of the Series A Preferred Stock. As of December 31, 2019, we had accrued $2.0 million related to dividends to holders of the Series A Preferred Stock. This dividend was paid on January 15, 2020. During the year ended December 31, 2018, the Company paid $7.0 million in dividends to holders of the Series A Preferred Stock and had accrued $2.0 million as of December 31, 2018.

On January 21, 2020, the Company declared a quarterly cash dividend in the amount of $0.546875 per share of Series A Preferred Stock. This amount represents an annualized dividend of $2.1875 per share. The dividend will be paid on April 15, 2020 to holders of record on April 1, 2020 of the Series A Preferred Stock.

A summary of our preferred equity balance for the years ended December 31, 2019 and 2018 is as follows:

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		(in thousands)
Balance at December 31, 2017		$	41,173
Issuance of Series A Preferred Stock, net of issuance cost		48,490
Accumulated dividends on Series A Preferred Stock		1,095
Balance at December 31, 2018		$	90,758
Repurchase of Series A Preferred Stock		(727		)
Accumulated dividends on Series A Preferred Stock		(16		)
Balance at December 31, 2019		$	90,015

7. Derivative Instruments

We are exposed to the impact of market fluctuations in the price of electricity and natural gas, basis differences in the price of natural gas, storage charges, renewable energy credits ("RECs"), and capacity charges from independent system operators. We use derivative instruments in an effort to manage our cash flow exposure to these risks. These instruments are not designated as hedges for accounting purposes, and accordingly, changes in the market value of these derivative instruments are recorded in the cost of revenues. As part of our strategy to optimize pricing in our natural gas related activities, we also manage a portfolio of commodity derivative instruments held for trading purposes. Our commodity trading activities are subject to limits within our Risk Management Policy. For these derivative instruments, changes in the fair value are recognized currently in earnings in net asset optimization revenues.

Derivative assets and liabilities are presented net in our consolidated balance sheets when the derivative instruments are executed with the same counterparty under a master netting arrangement. Our derivative contracts include transactions that are executed both on an exchange and centrally cleared, as well as over-the-counter, bilateral contracts that are transacted directly with third parties. To the extent we have paid or received collateral related to the derivative assets or liabilities, such amounts would be presented net against the related derivative asset or liability’s fair value. As of December 31, 2019 and 2018, we had paid $1.7 million and zero, respectively, in collateral. The specific types of derivative instruments we may execute to manage the commodity price risk include the following:

•	Forward contracts, which commit us to purchase or sell energy commodities in the future;

•	Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument;

•	Swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined notional quantity; and

•	Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity.

The Company has entered into other energy-related contracts that do not meet the definition of a derivative instrument or for which we made a normal purchase, normal sale election and are therefore not accounted for at fair value including the following:

•Forward electricity and natural gas purchase contracts for retail customer load;

•Renewable energy credits; and

•Natural gas transportation contracts and storage agreements.

Volumes Underlying Derivative Transactions

The following table summarizes the net notional volumes of our open derivative financial instruments accounted for at fair value by commodity. Positive amounts represent net buys while bracketed amounts are net sell transactions (in thousands):

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Non-trading 

Commodity	Notional		December 31, 2019			December 31, 2018
Natural Gas	MMBtu		6,130			8,176
Natural Gas Basis	MMBtu		42			115
Electricity	MWh		6,015			6,781

Trading

Commodity	Notional		December 31, 2019			December 31, 2018
Natural Gas	MMBtu		204			188
Natural Gas Basis	MMBtu		—			(380	)

Gains (Losses) on Derivative Instruments

Gains (losses) on derivative instruments, net and current period settlements on derivative instruments were as follows for the periods indicated (in thousands):

	Year Ended December 31,
	2019				2018				2017
(Loss) gain on non-trading derivatives, net	$	(67,955	)		$	(19,571	)		$	5,588
Gain (loss) on trading derivatives, net	206				1,401				(580		)
(Loss) gain on derivatives, net	$	(67,749	)		$	(18,170	)		$	5,008
Current period settlements on non-trading derivatives (1) (2)	42,944				(9,614		)		16,508
Current period settlements on trading derivatives	(124		)		(973		)		(199		)
Total current period settlements on derivatives (1) (2)	$	42,820			$	(10,587	)		$	16,309

(1) Excludes settlements of less than $0.1 million, $(0.3) million, and $3.4 million, respectively, for the years ended December 31, 2019, 2018, and 2017 related to non-trading derivative liabilities assumed in various acquisitions.

(2) Excludes settlements of $(0.9) million, zero, and zero, respectively, for the years ended December 31, 2019, 2018, and 2017 related to power call options.

Gains (losses) on trading derivative instruments are recorded in net asset optimization revenues and gains (losses) on non-trading derivative instruments are recorded in retail cost of revenues on the consolidated statements of operations.

Fair Value of Derivative Instruments

The following tables summarize the fair value and offsetting amounts of our derivative instruments by counterparty and collateral received or paid (in thousands):

 

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	December 31, 2019
Description	Gross Assets				Gross Amounts Offset				Net Assets				Cash Collateral Offset				Net Amount Presented
Non-trading commodity derivatives	$	570			$	(275	)		$	295			$	—			$	295
Trading commodity derivatives	170				(1		)		169				—				169
Total Current Derivative Assets	740				(276		)		464				—				464
Non-trading commodity derivatives	333				(227		)		106				—				106
Trading commodity derivatives	—				—				—				—				—
Total Non-current Derivative Assets	333				(227		)		106				—				106
Total Derivative Assets	$	1,073			$	(503	)		$	570			$	—			$	570

Description	Gross  Liabilities				Gross Amounts Offset				Net Liabilities				Cash Collateral Offset				Net Amount Presented
Non-trading commodity derivatives	$	(34,434	)		$	12,859			$	(21,575	)		$	1,632			$	(19,943	)
Trading commodity derivatives	(194		)		194				—				—				—
Total Current Derivative Liabilities	(34,628		)		13,053				(21,575		)		1,632				(19,943		)
Non-trading commodity derivatives	(1,951		)		1,422				(529		)		34				(495		)
Trading commodity derivatives	—				—				—				—				—
Total Non-current Derivative Liabilities	(1,951		)		1,422				(529		)		34				(495		)
Total Derivative Liabilities	$	(36,579	)		$	14,475			$	(22,104	)		$	1,666			$	(20,438	)

 

	December 31, 2018
Description	Gross Assets				Gross Amounts Offset				Net Assets				Cash Collateral Offset				Net Amount Presented
Non-trading commodity derivatives	$	18,649			$	(12,000	)		$	6,649			$	—			$	6,649
Trading commodity derivatives	734				(94		)		640				—				640
Total Current Derivative Assets	19,383				(12,094		)		7,289				—				7,289
Non-trading commodity derivatives	9,657				(6,381		)		3,276				—				3,276
Trading commodity derivatives	—				—				—				—				—
Total Non-current Derivative Assets	9,657				(6,381		)		3,276				—				3,276
Total Derivative Assets	$	29,040			$	(18,475	)		$	10,565			$	—			$	10,565

 

Description	Gross  Liabilities				Gross Amounts Offset				Net Liabilities				Cash Collateral Offset				Net Amount Presented
Non-trading commodity derivatives	$	(21,391	)		$	15,385			$	(6,006	)		$	—			$	(6,006	)
Trading commodity derivatives	(491		)		19				(472		)		—				(472		)
Total Current Derivative Liabilities	(21,882		)		15,404				(6,478		)		—				(6,478		)
Non-trading commodity derivatives	(71		)		40				(31		)		—				(31		)
Trading commodity derivatives	(135		)		60				(75		)		—				(75		)
Total Non-current Derivative Liabilities	(206		)		100				(106		)		—				(106		)
Total Derivative Liabilities	$	(22,088	)		$	15,504			$	(6,584	)		$	—			$	(6,584	)

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8. Property and Equipment

Property and equipment consist of the following (in thousands):

	Estimated  useful lives (years)		December 31, 2019				December 31, 2018
Information technology	2 – 5		$	22,005			$	34,611
Building and leasehold improvements	2 – 5		—				4,836
Furniture and fixtures	2 – 5		1,802				1,964
Total			23,807				41,411
Accumulated depreciation			(20,540		)		(37,045		)
Property and equipment—net			$	3,267			$	4,366

Information technology assets include software and consultant time used in the application, development and implementation of various systems including customer billing and resource management systems. As of each of December 31, 2019 and 2018, information technology includes $0.6 million and $0.3 million, respectively, of costs associated with assets not yet placed into service.

Depreciation expense recorded in the consolidated statements of operations was $2.3 million, $3.9 million and $2.6 million for the years ended December 31, 2019, 2018 and 2017, respectively.

9. Intangible Assets

Goodwill, customer relationships and trademarks consist of the following amounts (in thousands):

	December 31, 2019				December 31, 2018
Goodwill	$	120,343			$	120,343
Customer Relationships— Acquired
Cost	$	64,083			$	99,402
Accumulated amortization	(40,231		)		(63,208		)
Customer Relationships—Acquired & Non-Compete Agreements, net	$	23,852			$	36,194
Customer Relationships—Other
Cost	$	17,056			$	16,155
Accumulated amortization	(9,534		)		(9,290		)
Customer Relationships—Other, net	$	7,522			$	6,865
Trademarks
Cost	$	8,502			$	9,770
Accumulated amortization	(2,794		)		(2,483		)
Trademarks, net	$	5,708			$	7,287

Changes in goodwill, customer relationships (including non-compete agreements) and trademarks consisted of the following (in thousands):

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	Goodwill				Customer Relationships— Acquired & Non-Compete Agreements				Customer Relationships— Other				Trademarks
Balance at December 31, 2016	$	79,147			$	31,911			$	1,612			$	6,339
Adjustments (1)	260				—				—				—
Acquisition of Perigee	1,540				1,100				—				—
Acquisition of Verde	39,207				28,700				—				3,000
Additions (Other)	—				—				8,016				—
Amortization expense	—				(15,021		)		(2,826		)		(781		)
Balance at December 31, 2017	$	120,154			$	46,690			$	6,802			$	8,558
Additions	—				6,205				3,818				—
Adjustments (1)	189				(174		)		—				—
Amortization	—				(16,527		)		(3,755		)		(1,271		)
Balance at December 31, 2018	$	120,343			$	36,194			$	6,865			$	7,287
Additions	—				—				6,913				—
Amortization	—				(12,342		)		(6,256		)		(1,579		)
Balance at December 31, 2019	$	120,343			$	23,852			$	7,522			$	5,708

(1) Related to working capital adjustments on various acquisitions.

The acquired customer relationship intangibles related to Major Energy Companies, the Provider Companies, and the Verde Companies were bifurcated between hedged and unhedged customer contracts. The unhedged customer contracts are amortized to depreciation and amortization based on the expected future cash flows by year. The hedged customer contracts were evaluated for favorable or unfavorable positions at the time of acquisition and amortized to retail cost of revenue based on the expected term and position of the underlying fixed price contract in each reporting period. For the years ended December 31, 2019, 2018, and 2017, respectively, approximately less than $0.1 million, $(1.2) million, and $0.3 million of the $12.3 million, $16.5 million, and $15.0 million acquired customer relationship amortization expense is included in the cost of revenues.

Estimated future amortization expense for customer relationships and trademarks at December 31, 2019 is as follows (in thousands):

Year Ending December 31,
2020	$	14,561
2021	12,987
2022	6,038
2023	450
2024	249
> 5 years	2,797
Total	$	37,082

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10. Debt

Debt consists of the following amounts as of December 31, 2019 and 2018 (in thousands):

	December 31, 2019				December 31, 2018
Current:
Note Payable—Verde Notes	$	—			$	6,936
Total current portion of debt	—				6,936
Long-term debt:
Senior Credit Facility (1) (2)	123,000				129,500
Subordinated Debt	—				10,000
Total long-term debt	123,000				139,500
Total debt	$	123,000			$	146,436

(1) As of December 31, 2019 and 2018, the weighted average interest rate on the Senior Credit Facility was 4.71% and 5.48%, respectively.

(2) As of December 31, 2019 and 2018, we had $37.4 million and $49.4 million in letters of credit issued, respectively.

Capitalized financing costs associated with our Senior Credit Facility were $1.3 million and $1.4 million as of December 31, 2019 and 2018, respectively. Of these amounts, $0.9 million and $1.0 million are recorded in other current assets, and $0.4 million and $0.4 million are recorded in other non-current assets in the consolidated balance sheets as of December 31, 2019 and 2018, respectively.

Interest expense consists of the following components for the periods indicated (in thousands):

	Years Ended December 31,
	2019				2018				2017
Senior Credit Facility	$	5,263			$	5,300			$	3,275
Accretion related to Earnouts	—				—				4,108
Letters of credit fees and commitment fees	1,656				1,604				1,125
Amortization of deferred financing costs	1,275				1,291				1,035
Convertible subordinated notes to affiliate	—				—				1,052
Subordinated debt	197				26				167
Verde promissory note	230				1,189				372
Interest expense	$	8,621			$	9,410			$	11,134

Senior Credit Facility

The Company, as guarantor, and Spark HoldCo (the “Borrower” and, together with each subsidiary of Spark HoldCo (“Co-Borrowers”)) maintain a senior secured borrowing base credit facility (as amended, “Senior Credit Facility”) that allows us to borrow on a revolving basis and has a maximum borrowing capacity of $217.5 million as of December 31, 2019. Subject to applicable sublimits and terms of the Senior Credit Facility, as amended, borrowings are available for the issuance of letters of credit (“Letters of Credit”), working capital and general purpose revolving credit loans (“Working Capital Loans”), and bridge loans (“Bridge Loans”) for the purpose of partial funding for acquisitions. Borrowings under the Senior Credit Facility may be used to pay fees and expenses in connection with the Senior Credit Facility, finance ongoing working capital requirements and general corporate purpose requirements of the Co-Borrowers, to provide partial funding for acquisitions, as allowed under terms of the Senior Credit Facility, and to make open market purchases of our Class A common stock and Series A Preferred Stock.

The Senior Credit Facility will mature on May 19, 2021, and all amounts outstanding thereunder will be payable on the maturity date. Borrowings under the Bridge Loan sublimit, if any, will be repaid 25% per year on a quarterly

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basis (or 6.25% per quarter), with the remainder due at maturity. As of December 31, 2019, there was zero in Bridge Loans outstanding.

At our election, the interest rate for Working Capital Loans and Letters of Credit under the Senior Credit Facility is generally determined by reference to the Eurodollar rate plus an applicable margin of up to 3.00% per annum (based on the prevailing utilization) or an alternate base rate plus an applicable margin of up to 2.00% per annum (based on the prevailing utilization). The alternate base rate is equal to the highest of (i) the prime rate (as published in the Wall Street Journal), (ii) the federal funds rate plus 0.50% per annum, or (iii) the reference Eurodollar rate plus 1.00%.

Bridge Loan borrowings, if any, under the Senior Credit Facility are generally determined by reference to the Eurodollar rate plus an applicable margin of 3.75% per annum or an alternate base rate plus an applicable margin of 2.75% per annum. The alternate base rate is equal to the highest of (i) the prime rate (as published in the Wall Street Journal), (ii) the federal funds rate plus 0.50% per annum, or (iii) the reference Eurodollar rate plus 1.00%.

The Co-Borrowers pay a commitment fee of 0.50% quarterly in arrears on the unused portion of the Senior Credit Facility. In addition, the Co-Borrowers are subject to additional fees including an upfront fee, an annual agency fee, and letter of credit fees based on a percentage of the face amount of letters of credit payable to any syndicate member that issues a letter of credit.

The Senior Credit Facility contains covenants that, among other things, require the maintenance of specified ratios or conditions including:

•

Minimum Fixed Charge Coverage Ratio. We must maintain a minimum fixed charge coverage ratio of not less than 1.25 to 1.00. The Fixed Charge Coverage Ratio is defined as the ratio of (a) Adjusted EBITDA to (b) the sum of consolidated (with respect to the Company and the Co-Borrowers) interest expense (other than interest paid-in-kind in respect of certain subordinated debt but including interest in respect of that certain promissory note made by CenStar Energy Corp. ("CenStar") in connection with the permitted acquisition from Verde Energy USA Holdings, LLC), letter of credit fees, commitment fees, acquisition earn-out payments (excluding earnout payments funded with proceeds from newly issued preferred or common equity), distributions, the aggregate amount of repurchases of our Class A common stock, Series A Preferred Stock, or commitments for such purchases, taxes and scheduled amortization payments. The Senior Credit Facility permits, upon satisfaction of a Step-Down Condition, for the Company to elect to reduce the minimum required Fixed Charge Coverage Ratio from 1.25 to 1.00 to 1.10 to 1.00 for a period of one year. A Step-Down Condition is defined as the consummation by the Company of share buybacks of its Series A Preferred Stock under the Repurchase Program with an aggregate purchase price not less than $10.0 million.

•	Maximum Total Leverage Ratio. We must maintain a ratio of total indebtedness (excluding eligible subordinated debt and letter of credit obligations) to Adjusted EBITDA of no more than 2.50 to 1.00.

•

Maximum Senior Secured Leverage Ratio. We must maintain a Senior Secured Leverage Ratio of no more than 1.85 to 1.00. The Senior Secured Leverage Ratio is defined as the ratio of (a) all indebtedness of the loan parties on a consolidated basis that is secured by a lien on any property of any loan party (including the effective amount of all loans then outstanding under the Senior Credit Facility) plus 50% of the effective amount of letter of credit obligations attributable to performance standby letters of credit to (b) Adjusted EBITDA.

The Senior Credit Facility contains various negative covenants that limit our ability to, among other things, incur certain additional indebtedness, grant certain liens, engage in certain asset dispositions, merge or consolidate, make certain payments, distributions, investments, acquisitions or loans, materially modify certain agreements, or enter into transactions with affiliates. The Senior Credit Facility also contains affirmative covenants that are customary

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for credit facilities of this type. As of December 31, 2019, we were in compliance with our various covenants under the Senior Credit Facility.

The Senior Credit Facility is secured by pledges of the equity of the portion of Spark HoldCo owned by us, the equity of Spark HoldCo’s subsidiaries, the Co-Borrowers’ present and future subsidiaries, and substantially all of the Co-Borrowers’ and their subsidiaries’ present and future property and assets, including accounts receivable, inventory and liquid investments, and control agreements relating to bank accounts.

We are entitled to pay cash dividends to the holders of the Series A Preferred Stock and Class A common stock and will be entitled to repurchase up to an aggregate amount of 10,000,000 shares of our Class A common stock, and up to $92.7 million of Series A Preferred Stock through one or more normal course open market purchases through NASDAQ so long as: (a) no default exists or would result therefrom; (b) the Co-Borrowers are in pro forma compliance with all financial covenants before and after giving effect thereto; and (c) the outstanding amount of all loans and letters of credit does not exceed the borrowing base limits.

The Senior Credit Facility contains certain customary representations and warranties and events of default. Events of default include, among other things, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments in excess of $5.0 million, certain events with respect to material contracts, and actual or asserted failure of any guaranty or security document supporting the Senior Credit Facility to be in full force and effect. A default will also occur if at any time W. Keith Maxwell III ceases to, directly or indirectly, own at least 13,600,000 Class A and Class B shares on a combined basis (to be adjusted for any stock split, subdivisions or other stock reclassification or recapitalization), and a controlling percentage of the voting equity interest of the Company, and certain other changes in control. If such an event of default occurs, the lenders under the Senior Credit Facility would be entitled to take various actions, including the acceleration of amounts due under the facility and all actions permitted to be taken by a secured creditor.

Convertible Subordinated Notes to Affiliate

In connection with the financing of the CenStar and Oasis acquisitions, the Company issued Notes totaling $7.1 million, at an annual interest rate of 5%, payable semiannually. In January 2017, these Notes were converted into 1,035,642 shares of Class B common stock (and related Spark HoldCo units).

Subordinated Debt Facility

In June 2019, the Company entered into an Amended and Restated Subordinated Promissory Note in the principal amount of up to $25.0 million (the “Subordinated Debt Facility”), by and among the Company, Spark HoldCo and Retailco. The Subordinated Debt Facility amended and restated the Subordinated Promissory Note, dated as of December 27, 2016, by and among the Company, Spark HoldCo and Retailco, solely to extend the expiration date from July 1, 2020 to December 31, 2021.

The Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the Subordinated Debt Facility. Advances thereunder accrue interest at 5% per annum from the date of the advance. We have the right to capitalize interest payments under the Subordinated Debt Facility. The Subordinated Debt Facility is subordinated in certain respects to our Senior Credit Facility pursuant to a subordination agreement. We may pay interest and prepay principal on the Subordinated Debt Facility so long as we are in compliance with the covenants under our Senior Credit Facility, are not in default under the Senior Credit Facility and have minimum availability of $5.0 million under the borrowing base under the Senior Credit Facility. Payment of principal and interest under the Subordinated Debt Facility is accelerated upon the occurrence of certain change of control or sale transactions.

As of December 31, 2019 and 2018, there was zero and $10.0 million outstanding under the Subordinated Debt Facility.

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Verde Notes

In connection with the acquisition of the Verde Companies in July 2017, we entered into a promissory note in the aggregate principal amount of $20.0 million (the "Verde Promissory Note"). The Verde Promissory Note required repayment in 18 monthly installments beginning in August 2017, and accrued interest at 5% per annum from the date of issuance. The Verde Promissory Note, including principal and interest, was unsecured, but was guaranteed by us. In January 2018, in connection with the Earnout Termination Agreement (defined below), we issued to the seller of the Verde Companies an amended and restated promissory note (the “Amended and Restated Verde Promissory Note”), which amended and restated the Verde Promissory Note. The Amended and Restated Verde Promissory Note matured in January 2019, and bore interest at a rate of 9% per annum. Principal and interest were payable monthly on the first day of each month, with a portion of each payment going into an escrow account, which serves as security for certain indemnification claims and obligations under the Verde purchase agreement. As of December 31, 2019 and 2018, there was zero and $1.0 million outstanding, respectively, under the Amended and Restated Verde Promissory Note.

In January 2018, we issued a promissory note in the principal amount of $5.9 million in connection with an agreement to terminate the earnout obligations arising in connection with our acquisition of the Verde Companies (the “Verde Earnout Termination Note”). The Verde Earnout Termination Note matured in June 2019 and bore interest at a rate of 9% per annum. Under the terms of the Verde Earnout Termination Note, we were permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters. A payment of $1.0 million was made to the seller of the Verde Companies in June 2019, and $4.9 million was withheld (the “Verde Holdback”) to be applied to indemnifiable matters. As of December 31, 2019 and 2018, there was zero and $5.9 million outstanding under the Verde Earnout Termination Note, respectively.

The Verde Earnout Termination Note, the Verde Promissory Note, and the Amended and Restated Verde Promissory Note are collectively referred to as the "Verde Notes."

11. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes the credit standing of counterparties involved and the impact of credit enhancements.

We apply fair value measurements to our commodity derivative instruments and contingent payment arrangements based on the following fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value into three broad levels:

•	Level 1—Quoted prices in active markets for identical assets and liabilities. Instruments categorized in Level 1 primarily consist of financial instruments such as exchange-traded derivative instruments.

•

Level 2—Inputs other than quoted prices recorded in Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps and options.

•	Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, observable market activity for the asset or liability. The Level 3 category includes estimated earnout obligations related to our acquisitions.

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As the fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3), the Company maximizes the use of observable inputs and minimizes the use of unobservable inputs when measuring fair value. These levels can change over time. In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present assets and liabilities measured and recorded at fair value in our consolidated balance sheets on a recurring basis by and their level within the fair value hierarchy (in thousands):

	Level 1				Level 2				Level 3				Total
December 31, 2019
Non-trading commodity derivative assets	$	—			$	401			$	—			$	401
Trading commodity derivative assets	—				169				—				169
Total commodity derivative assets	$	—			$	570			$	—			$	570
Non-trading commodity derivative liabilities	$	(1,666	)		$	(18,772	)		$	—			$	(20,438	)
Trading commodity derivative liabilities	—				—				—				—
Total commodity derivative liabilities	$	(1,666	)		$	(18,772	)		$	—			$	(20,438	)
Contingent payment arrangement	$	—			$	—			$	—			$	—

	Level 1				Level 2				Level 3				Total
December 31, 2018
Non-trading commodity derivative assets	$	104			$	9,821			$	—			$	9,925
Trading commodity derivative assets	44				596				—				640
Total commodity derivative assets	$	148			$	10,417			$	—			$	10,565
Non-trading commodity derivative liabilities	$	(352	)		$	(5,685	)		$	—			$	(6,037	)
Trading commodity derivative liabilities	(75		)		(472		)		—				(547		)
Total commodity derivative liabilities	$	(427	)		$	(6,157	)		$	—			$	(6,584	)
Contingent payment arrangement	$	—			$	—			$	(1,328	)		$	(1,328	)

We had no transfers of assets or liabilities between any of the above levels during the years ended December 31, 2019, 2018 and 2017.

Our derivative contracts include exchange-traded contracts valued utilizing readily available quoted market prices and non-exchange-traded contracts valued using market price quotations available through brokers or over-the-counter and on-line exchanges. In addition, in determining the fair value of our derivative contracts, we apply a credit risk valuation adjustment to reflect credit risk, which is calculated based on our or the counterparty’s historical credit risks. As of December 31, 2019 and 2018, the credit risk valuation adjustment was a gain of $0.2 million and zero, respectively.

The contingent payment arrangements referred to above reflect estimated earnout obligations incurred in relation to our acquisition of the Major Energy Companies in 2016.

Contingent Payment Arrangements

The following tables present a roll forward of our contingent payment arrangements, which are measured at fair value on a recurring basis using significant unobservable inputs (Level 3):

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		Major Earnout and Stock Earnout
Fair Value at December 31, 2017		$	4,650
Change in fair value of contingent consideration, net		$	(1,715	)
Payments and settlements		(1,607		)
Fair Value at December 31, 2018		$	1,328
Transfer		(1,328		)
Fair Value at December 31, 2019		$	—

The Major Earnout is based on the achievement by the Major Energy Companies of certain performance targets over a 33 month period following the date our affiliate acquired the Major Energy Companies and ended on December 31, 2018. Under the Earnout provisions, the previous members of Major Energy Companies were entitled to a maximum of $20.0 million in earnout payments based on the level of performance targets attained, as defined by the Major Purchase Agreement. The Stock Earnout obligation was contingent upon the Major Energy Companies achieving the Major Earnout's performance target ceiling, thereby earning the maximum Major Earnout payments. If the Major Energy Companies earned such maximum Major Earnout payments, NG&E would be entitled to additional consideration up to a maximum of 400,000 shares of Class B common stock (and a corresponding number of Spark HoldCo units). In determining the fair value of the Major Earnout and the Stock Earnout, we forecasted certain expected performance targets and calculated the probability of such forecast being attained. The impact of the fair value decreases for the years ended December 31, 2018 and 2017 were recorded in general and administrative expenses. The $1.3 million has not been paid as of December 31, 2019 due to ongoing litigation with the Major sellers. It was transferred to accrued liabilities as of December 31, 2019, as discussed further in Note 14 "Commitments and Contingencies."

12. Stock-Based Compensation

Restricted Stock Units

We maintain a Long-Term Incentive Plan ("LTIP") for employees, consultants and directors of the Company and its affiliates who perform services for the Company. The purpose of the LTIP is to provide a means to attract and retain individuals to serve as directors, employees and consultants who provide services to the Company by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of the Company’s Class A common stock. The LTIP provides for grants of cash payments, stock options, stock appreciation rights, restricted stock or units, bonus stock, dividend equivalents, and other stock-based awards with the total number of shares of stock available for issuance under the LTIP not to exceed 2,750,000 shares.

Restricted stock units granted to our officers, employees, non-employee directors and certain employees of our affiliates who perform services for the Company vest over approximately one year for non-employee directors and ratably over approximately one to four years for officers, employees, and employees of affiliates, with the initial vesting date occurring in May of the subsequent year. Each restricted stock unit is entitled to receive a dividend equivalent when dividends are declared and distributed to shareholders of Class A common stock. These dividend equivalents are retained by the Company, reinvested in additional restricted stock units effective as of the record date of such dividends and vested upon the same schedule as the underlying restricted stock unit.

The Company measures the cost of awards classified as equity awards based on the grant date fair value of the award, and the Company measures the cost of awards classified as liability awards at the fair value of the award at each reporting period. The Company has utilized an estimated 6% annual forfeiture rate of restricted stock units in determining the fair value for all awards excluding those issued to executive level recipients and non-employee directors, for which no forfeitures are estimated to occur. The Company has elected to recognize related compensation expense on a straight-line basis over the associated vesting periods.

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Although the restricted stock units allow for cash settlement of the awards at the sole discretion of management of the Company, management intends to settle the awards by issuing shares of the Company’s Class A common stock.

Total stock-based compensation expense for the years ended December 31, 2019, 2018 and 2017 was $5.5 million, $5.9 million and $5.1 million. Total income tax benefit related to stock-based compensation recognized in net income (loss) was $0.6 million, $0.6 million and $0.8 million for the years ended December 31, 2019, 2018 and 2017.

Equity Classified Restricted Stock Units

Restricted stock units issued to employees and officers of the Company are classified as equity awards. The fair value of the equity classified restricted stock units is based on the Company’s Class A common stock price as of the grant date. The Company recognized stock based compensation expense of $5.0 million, $5.3 million and $2.8 million for the years ended December 31, 2019, 2018 and 2017, respectively, in general and administrative expense with a corresponding increase to additional paid in capital. The following table summarizes equity classified restricted stock unit activity and unvested restricted stock units for the year ended December 31, 2019:

	Number of Shares (in thousands)		Weighted Average Grant Date Fair Value
Unvested at December 31, 2018	827		$	10.09
Granted	547		9.53
Dividend reinvestment issuances	53		10.07
Vested	(450	)	9.60
Forfeited	(148	)	10.72
Unvested at December 31, 2019	829		$	9.88

For the year ended December 31, 2019, 449,725 restricted stock units vested, with 284,896 shares of Class A common stock distributed to the holders of these units and 164,829 shares of Class A common stock withheld by the Company to cover taxes owed on the vesting of such units. As of December 31, 2019, there was $5.1 million of total unrecognized compensation cost related to the Company’s equity classified restricted stock units, which is expected to be recognized over a weighted average period of approximately 2.5 years.

Change in Control Restricted Stock Units

In 2018, the Company granted Change in Control Restricted Stock Units ("CIC RSUs") to certain officers that vest upon a "Change in Control", if certain conditions are met. The terms of the CIC RSUs define a "Change in Control" to generally mean:

–	the consummation of an agreement to acquire or tender offer for beneficial ownership by any person, of 50% or more of the combined voting power of our outstanding voting securities entitled to vote generally in the election of directors, or by any person of 90% or more of the then total outstanding shares of Class A common stock;

–	individuals who constitute the incumbent board cease for any reason to constitute at least a majority of the board;

–	consummation of certain reorganizations, mergers or consolidations or a sale or other disposition of all or substantially all of our assets;

–	approval by our stockholders of a complete liquidation or dissolution;

–	a public offering or series of public offerings by Retailco and its affiliates, as a selling shareholder group, in which their total interest drops below 10 million of our total outstanding voting securities;

–	a disposition by Retailco and its affiliates in which their total interest drops below 10 million of our total outstanding voting securities; or

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–	any other business combination, liquidation event of Retailco and its affiliates or restructuring of us which the Compensation Committee deems in its discretion to achieve the principles of a Change in Control.

The equity classified restricted stock unit table above excludes unvested CIC RSUs as the conditions for Change in Control have not been met. The Company has not recognized stock compensation expense related to the CIC RSUs as the Change in Control conditions have not been met.

Liability Classified Restricted Stock Units

Restricted stock units issued to non-employee directors of the Company and employees of certain of our affiliates are classified as liability awards as the awards are either to a) non-employee directors that allow for the recipient to choose net settlement for the amount of withholding taxes dues upon vesting or b) to employees of certain affiliates of the Company and are therefore not deemed to be employees of the Company. The fair value of the liability classified restricted stock units is based on the Company’s Class A common stock price as of the reported period ending date. The Company recognized stock based compensation expense of $0.5 million, $0.6 million and $2.3 million for years ended December 31, 2019, 2018 and 2017, respectively, in general and administrative expense with a corresponding increase to liabilities. As of December 31, 2019, the Company’s liabilities related to these restricted stock units recorded in current liabilities was $0.2 million. As of December 31, 2018, the Company's liabilities related to these restricted stock units recorded in current liabilities was $0.2 million. The following table summarizes liability classified restricted stock unit activity and unvested restricted stock units for the year ended December 31, 2019:

	Number of Shares (in thousands)		Weighted Average Reporting Date Fair Value
Unvested at December 31, 2018	68		$	7.43
Granted	76		9.23
Dividend reinvestment issuances	4		9.23
Vested	(24	)	10.25
Forfeited	(96	)	9.27
Unvested at December 31, 2019	28		$	9.23

For the year ended December 31, 2019, 23,767 restricted stock units vested, with 15,819 shares of Class A common stock distributed to the holders of these units and 7,948 shares of Class A common stock withheld by the Company to cover taxes owed on the vesting of such units. As of December 31, 2019, there was $0.1 million of total unrecognized compensation cost related to the Company’s liability classified restricted stock units, which is expected to be recognized over a weighted average period of approximately 0.4 years.

13. Income Taxes

We and our subsidiaries, CenStar and Verde Energy USA, Inc. ("Verde Corp") are each subject to U.S. federal income tax as corporations. CenStar and Verde Corp file consolidated tax returns in jurisdictions that allow combined reporting. Spark HoldCo and its subsidiaries, with the exception of CenStar and Verde Corp, are treated as flow-through entities for U.S. federal income tax purposes, and, as such, are generally not subject to U.S. federal income tax at the entity level. Rather, the tax liability with respect to their taxable income is passed through to their members or partners. Accordingly, we are subject to U.S. federal income taxation on our allocable share of Spark HoldCo's net U.S. taxable income.

In our financial statements, we report federal and state income taxes for our share of the partnership income attributable to our ownership in Spark HoldCo and for the income taxes attributable to CenStar and Verde Corp. Net income attributable to non-controlling interest includes the provision for income taxes related to CenStar and Verde Corp.

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We account for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and the tax bases of the assets and liabilities. We apply existing tax law and the tax rate that we expect to apply to taxable income in the years in which those differences are expected to be recovered or settled in calculating the deferred tax assets and liabilities. Effects of changes in tax rates on deferred tax assets and liabilities are recognized in income in the period of the tax rate enactment. A valuation allowance is recorded when it is not more likely than not that some or all of the benefit from the deferred tax asset will be realized.

In December 2017, the President signed the U.S. Tax Reform legislation, which enacted a wide range of changes to the U.S. Corporate income tax system. Accordingly, we adjusted the value of our U.S. deferred tax assets and liabilities based on the rates at which they are expected to be recognized in the future. For U.S. federal purposes the corporate statutory income tax rate was reduced from 35% to 21%, effective for the 2018 tax year. During 2018, we completed our analysis of the impact of U.S. Tax Reform based on further guidance provided on the new tax law by the U.S. Treasury Department and Internal Revenue Service, with no material changes from our assessment performed as of December 31, 2017.

The provision for income taxes for the years ended December 31, 2019, 2018, and 2017 included the following components:

(in thousands)		2019				2018				2017
Current:
Federal		$	10,511			$	3,862			$	6,992
State		3,675				1,099				1,952
Total Current		14,186				4,961				8,944
Deferred:
Federal		(4,668		)		(2,792		)		27,820
State		(2,261		)		(92		)		2,001
Total Deferred		(6,929		)		(2,884		)		29,821
Provision for income taxes		$	7,257			$	2,077			$	38,765

 

The effective income tax rate was 34%, (17)%, and 34% for the years ended December 31, 2019, 2018, and 2017, respectively. The following table reconciles the income tax benefit that would result from application of the statutory federal tax rate, 21%, 21%, and 35% for the years ended December 31, 2019, 2018, and 2017 respectively, to the amount included in the consolidated statement of operations:

(in thousands)	2019				2018				2017
Expected provision at federal statutory rate	$	4,509			$	(2,586	)		$	39,833
(Decrease) increase resulting from:
Non-controlling interest	(1,329		)		1,738				(19,810		)
Class A Preferred Stock dividends	1,341				1,579				1,758
Impact of U.S. Tax Reform	—				—				14,454
Intra-entity transfer of customer contracts	—				473				—
State income taxes, net of federal income tax effect	1,382				428				2,569
Prior year true-up	1,060				(31		)		—
Non-deductible expenses	256				256				234
Other	38				220				(273		)
Provision for income taxes	$	7,257			$	2,077			$	38,765

Total income tax expense for the years ended December 31, 2019 and 2018 differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income primarily due to state income taxes and the impact of permanent differences between book and taxable income, most notably the income attributable to non-controlling interest, which gets taxed at the non-controlling interest partner level. The effective rate in 2017 was also impacted

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by the enactment of U.S. Tax Reform. Since we were in a net deferred tax asset position, the rate reduced our overall asset having an unfavorable effect on tax expense.

The components of our deferred tax assets as of December 31, 2019 and 2018 are as follows:

(in thousands)	2019			2018
Deferred Tax Assets:
Investment in Spark HoldCo	$	28,671		$	22,251
Benefit of TRA Liability	—			7,016
State net operating loss carryforward	140			—
Derivative Liabilities	1,669			—
Other	220			78
Total deferred tax assets	30,700			29,345
Deferred Tax Liabilities:
Derivative liabilities	—			(715		)
Intangibles	(808		)	(849		)
Property and equipment	(27		)	(460		)
Total deferred tax liabilities	(835		)	(2,024		)
Total deferred tax assets/liabilities	$	29,865		$	27,321

The benefit of the TRA Liability as of December 31, 2018 related to the step up in tax basis resulting from the purchase by the Company of Spark HoldCo units from our Founder at the time of our IPO. Subsequent issuances of Series A common stock, exchanges of Series A Common Stock for Series B Shares and vesting of incentive stock compensation since our IPO also resulted in step ups in the basis of our stock similarly resulting in a liability under our Tax Receivable Agreement prior to it being settled in July 2019. As a result of the settlement, there is no outstanding liability as of December 31, 2019. For the period ending December 31, 2018, we had a current liability of $1.7 million and a long-term liability of $25.9 million to reflect the obligation under the Tax Receivable Agreement. See Note 15 "Transactions with Affiliates" for further discussion.

We periodically assess whether it is more likely than not that we will generate sufficient taxable income to realize our deferred income tax assets. In making this determination, we consider all available positive and negative evidence and makes certain assumptions. We consider, among other things, our deferred tax liabilities, the overall business environment, our historical earnings and losses, current industry trends, and our outlook for future years. We believe it is more likely than not that our deferred tax assets will be utilized, and accordingly have not recorded a valuation allowance on these assets.

The tax years 2013 through 2017 remain open to examination by the major taxing jurisdictions to which the Company is subject to income tax. An affiliate owned by our Founder would be responsible for any audit adjustments incurred in connection with transactions occurring prior to July 2014 for Spark Energy, Inc. and Spark HoldCo.

Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2019 and 2018 there was no liability, and for the years ended December 31, 2019, 2018 and 2017, there was no expense recorded for interest and penalties associated with uncertain tax positions or unrecognized tax positions. Additionally, the Company does not have unrecognized tax benefits as of December 31, 2019 and 2018.

14. Commitments and Contingencies

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From time to time, we may be involved in legal, tax, regulatory and other proceedings in the ordinary course of business. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Legal Proceedings

Below is a summary of our currently pending material legal proceedings. We are subject to lawsuits and claims arising in the ordinary course of our business. The following legal proceedings are in various stages and are subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, unless otherwise specifically noted, we cannot currently predict the manner and timing of the resolutions of these legal proceedings or estimate a range of possible losses or a minimum loss that could result from an adverse verdict in a potential lawsuit. While the lawsuits and claims are asserted for amounts that may be material should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations.

Consumer Rate Lawsuits

The Company, like other ESCOs in the industry, is subject to several class actions in various jurisdictions where the Company sells energy, such actions alleging consumers paid higher rates than they would have if they stayed with the default utility.

Janet Rolland, et al v. Spark Energy, LLC is a purported class action originally filed on April 19, 2017 in the United States District Court for the District of New Jersey alleging that Spark Energy, LLC charged a variable rate that was higher than permitted by its terms of service, resulting in breach of contract and violation of the duty of good faith and fair dealing. Plaintiffs alleged claims under the New Jersey Consumer Fraud Act and Illinois Consumer Fraud and Deceptive Business Practices Act. The case seeks to certify a putative nationwide class of all Spark variable rate electricity customers from April 19, 2011 to the present. The relief sought includes unspecified actual damages, refunds, treble damages and punitive damages for the putative class, injunctive relief, attorneys’ fees and costs of suit. Spark obtained dismissal with prejudice of the New Jersey Consumer Fraud Act claim and has sought dismissal of the Illinois Consumer Fraud and Deceptive Business Practices Act claim and other claims. Discovery is ongoing in this matter. Spark denies the allegations asserted by Plaintiffs and intends to vigorously defend this matter. Given the ongoing discovery and current stage of this matter, we cannot predict the outcome of this case at this time.

Katherine Veilleux, et. al. v. Electricity Maine LLC, Provider Power, LLC, Spark HoldCo, LLC, Kevin Dean, and Emile Clavet is a purported class action lawsuit filed on November 18, 2016 in the United States District Court of Maine, alleging that Electricity Maine, LLC ("Electricity Maine"), an entity acquired by Spark Holdco in mid-2016, enrolled customers and conducted advertising, and promotions not in compliance with law. Plaintiffs seek damages for themselves and the purported class, injunctive relief, restitution, and attorneys' fees. The parties are completing a settlement agreement and will present such Agreement to the court for approval, which we expect the court to review in second quarter of 2020.

Gillis et al. v. Respond Power, LLC is a purported class action lawsuit that was originally filed on May 21, 2014 in the Philadelphia Court of Common Pleas but was later removed to the United States District Court for the Eastern District of Pennsylvania. On July 16, 2018, the district court granted Respond Power LLC's motion to dismiss the Plaintiff’s class action claims. Plaintiffs filed their notice of appeal to the Third Circuit Court on August 7, 2018. The Third Circuit ruled in favor of Respond Power on February 3, 2019. Barring an appeal to the Supreme Court of United States, this matter has been resolved in Respond Power's favor.

Jurich v. Verde Energy USA, Inc. is a class action originally filed on March 3, 2015 in the United States District Court for the District of Connecticut and subsequently re-filed on October 8, 2015 in the Superior Court of Judicial District of Hartford, State of Connecticut. The Amended Complaint asserts that the Verde Companies charged rates in violation of its contracts with Connecticut customers and alleges (i) violation of the Connecticut Unfair Trade

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Practices Act, Conn. Gen. Stat. §§ 42-110a et seq., and (ii) breach of the covenant of good faith and fair dealing. Plaintiffs are seeking unspecified actual and punitive damages for the class and injunctive relief. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter. The parties have reached a class settlement in this matter, which has received final court approval, and an order of dismissal on February 24, 2020. Settlement claims’ administration is continuing. The Company believes it has full indemnity coverage, net of tax benefit, for any actual exposure in this case at this time.

Telemarketing Lawsuits

Albrecht v. Oasis Power, LLC is a putative nationwide class action that was filed on February 12, 2018 in the United States District Court for the Northern District of Illinois, alleging that Oasis made illegal prerecorded telemarketing calls, including auto-dialed calls, to consumers’ mobile phones, in violation of the Telephone Consumer Protection Act ("TCPA") and the Illinois Automatic Telephone Dialers Act ("ATDA"). Plaintiff sought an injunction requiring Oasis to cease all unsolicited calling activities, an award of statutory and trebled damages under the TCPA and the ATDA, as well as costs and attorney’s fees. The parties have reached a class settlement on behalf of Oasis and other affiliated brands in the amount of $7.0 million, which received final court approval on February 6, 2020. Settlement claims’ administration has commenced.

Richardson et. al. v. Verde Energy USA, Inc. is a purported class action filed on November 25, 2015 in the United States District Court for the Eastern District of Pennsylvania alleging that the Verde Companies violated the Telephone Consumer Protection Act ("TCPA") by placing marketing calls using an automatic telephone dialing system ("ATDS") or a prerecorded voice to the purported class members’ cellular phones without prior express consent and by continuing to make such calls after receiving requests for the calls to cease. Following discovery and dispositive motions, the Verde Companies received a favorable ruling on summary judgment with the court agreeing with the Verde Companies that the call system used in this case was not an ATDS as defined by the TCPA. Plaintiffs subsequently amended their petition eliminating their ATDS claim and including a class based on failure to comply with the National Do Not Call registry. As part of an agreement in connection with the acquisition of the Verde Companies, the original owners of the Verde Companies are handling this matter. The parties reached a settlement in this matter. On January 17, 2020, the court approved the Parties’ preliminary settlement and settlement claims’ administration has commenced. The Company believes it has full indemnity coverage, net of tax benefit, for the settlement exposure in this case.

Corporate Matter Lawsuits

Saul Horowitz, as Sellers’ Representative for the former owners of the Major Energy Companies v. National Gas & Electric, LLC ("NG&E") and Spark Energy, Inc., is a lawsuit filed on October 17, 2017 in the United States District Court for the Southern District of New York asserting claims of fraudulent inducement against NG&E, breach of contract against NG&E and Spark, and tortious interference with contract against Spark related to a membership interest purchase agreement, subsequent dropdown, and associated earnout agreements with the Major Energy Companies' former owners. The relief sought includes unspecified compensatory and punitive damages, prejudgment and post-judgment interest, and attorneys’ fees. On September 24, 2018, the court granted Defendants’ motion to dismiss in part and dismissed Plaintiffs’ fraudulent inducement claims. NG&E and Spark filed their affirmative defenses and answer to the remaining claims on October 15, 2018. On January 14, 2019, Plaintiffs filed a Motion for Partial Summary Judgment, which was subsequently denied by the Court on May 8, 2019. On March 25, 2019, Spark and NG&E filed a Motion for Sanctions in connection with deletion of electronically stored data by plaintiff Saul Horowitz and co-seller Mark Wiederman after receiving a litigation hold notice, which the Court granted in part on May 8, 2019, including an award of attorneys' fees and costs to Spark and NG&E in connection with the Motion for Sanctions. On June 7, 2019, the parties jointly filed a letter agreement with the Court confirming plaintiff’s payment of fees and costs, including costs associated with forensic analysis, in the amount of less than $0.1 million to Spark and NG&E in connection with the Court’s ruling on their Motion for Sanctions. This case is set for trial to commence on March 2, 2020. Spark and NG&E deny the allegations asserted by Plaintiffs and intend to vigorously defend this matter.

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Regulatory Matters

Many state regulators have increased scrutiny on retail energy providers, across all industry providers. We are subject to regular regulatory inquiries and preliminary investigations in the ordinary course of our business. Below is a summary of our currently pending material state regulatory matters. The following state regulatory matters are in various stages and are subject to substantial uncertainties concerning the outcome of material factual and legal issues. Accordingly, we cannot currently predict the manner and timing of the resolution of these state regulatory matters or estimate a range of possible losses or a minimum loss that could result from an adverse action. Management does not currently expect that any currently pending state regulatory matters will have a material adverse effect on our financial position or results of operations.

Connecticut. Spark Energy, LLC ("SE LLC") has been working with the Connecticut Public Utilities Regulatory Authority ("PURA") regarding compliance with requirements implemented in 2016 that customer bills include any changes to existing rates effective for the next billing cycle. SE LLC and other ESCOs in Connecticut have agreed to submit to a proceeding offering amnesty to ESCOs that self-report violations and offer to voluntarily remit refunds to customers. Spark has remitted its report of potential customers who would be eligible for refunds under the amnesty program and submitted its confidential settlement proposal along with SE LLC’s commitment, subject to certain conditions. SE LLC is awaiting PURA’s completion of a review and audit process after which SE LLC expects PURA to issue a final decision on SE LLC’s offer of amnesty.

Illinois. The Illinois Attorney General brought action against Major Energy Electric Services, LLC ("Major") for injunctive and other relief asserting claims that Major engaged in a pattern and practice of non-compliance with law through door-to-door and telephone solicitations, in-person solicitations at retail establishments, advertisements on its website and direct mail advertisements to sign up for electricity services. The complaint seeks injunctive relief and monetary damages representing the amounts Illinois consumers have allegedly lost due to such non-compliant marketing activities. The Attorney General also requested civil penalties. The parties resolved this matter on August 16, 2019. A final judgment and consent decree was entered into, which included Major paying $2.0 million in refunds to consumers, and $0.1 million as a voluntary contribution to the Illinois Attorney General's Office. The settlement also included a number of injunctive and reporting provisions with which Major must comply. Major has made the refund payment.

In a separate matter, Spark Energy, LLC received a verbal inquiry from the Illinois Commerce Commission ("ICC") and the Illinois Attorney General ("IAG") on January 1, 2020 seeking to understand an increase in complaints from Illinois consumers. The Company met with the ICC and the IAG in February 2020 and plan to discuss a compliance plan to ensure its sales are in compliance with Illinois regulations. The parties also discussed possible restitution payments to any customers impacted by sales not in compliance with Illinois regulations.

Maine. In early 2018, Staff of the Maine Public Utilities Commission (“Maine PUC”) issued letters to Electricity Maine seeking information about customer complaints principally associated with door-to-door (“D2D”) sales practices. In late July 2018, the Maine PUC issued an Order to Show Cause to which Electricity Maine filed a detailed response in mid-August 2018. After a lengthy period of inactivity, the Commission scheduled a procedural conference in early 2019 that resulted in no intervenors other than participation as a party by the Maine Office of Public Advocate. At the conference, the parties agreed on a procedural schedule, including a one-day evidentiary hearing. Following post-hearing discovery, Initial and Reply Briefs were filed on August 30, 2019 and September 10, 2019, respectively. The parties are awaiting a proposed ruling from the Maine PUC hearing examiner, after which point the parties can either accept the ruling or take exception and argue the merits before the Maine PUC Commissioners. While investigations of this nature may be resolved in a manner that allows the retail energy supplier to continue operating in Maine with stipulations, there can be no assurances that Maine PUC will not take more severe action.

New York. Prior to the purchase of Major Energy by the Company, in 2015, Major Energy Services, LLC and Major Energy Electric Services were contacted by the Attorney General, Bureau of Consumer Frauds & Protection for State of New York relating to their marketing practices. Major Energy has exchanged information in response to various requests from the Attorney General. The Parties are in settlement negotiations at this time. While

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investigations of this nature may be resolved in a manner that allows the retail energy supplier to continue operating in New York with stipulations, there can be no assurances that the New York Attorney General will not take more severe action.

Ohio. Verde Energy USA Ohio, LLC (“Verde Ohio”) is the subject of a formal investigation by the Public Utilities Commission of Ohio (“PUCO”) initiated on April 16, 2019. The investigation asserts that Verde Ohio may have violated Ohio’s retail energy supplier regulations. Verde Ohio voluntary suspended door-to-door marketing in Ohio in furtherance of settlement negotiations with the PUCO Staff. On September 6, 2019, Verde Ohio and PUCO Staff executed and filed with PUCO a Joint Stipulation and Recommendation for PUCO’s review and approval which sets forth agreed settlement terms, which includes a $1.7 million settlement amount. If approved by PUCO, the Joint Stipulation and Recommendation would resolve all of the issues raised in the investigation. In addition, in September of 2019, the Ohio Attorney General (“OAG”) alleged that Verde Ohio had violated its Consumer Sales Practice Act and Do Not Call regulations. Verde Ohio is cooperating and responding to the OAG’s document requests; however, at this time, the Company cannot predict the outcome of this matter.

Pennsylvania. Verde Energy USA, Inc. (“Verde”) is the subject of a formal investigation by the Pennsylvania Public Utility Commission, Bureau of Investigation and Enforcement (“PPUC”) initiated on January 30, 2020. The investigation asserts that Verde may have violated Pennsylvania retail energy supplier regulations. The Company met with the PPUC in February 2020 to discuss the matter and work with the PPUC cooperatively. Verde is cooperating and responding to the PPUC's requests for information. Currently, the Company cannot predict the outcome at this time.

Indirect Tax Audits

We are undergoing various types of indirect tax audits spanning from years 2013 to 2018 for which we may have additional liabilities arise. At the time of filing these consolidated financial statements, these indirect tax audits are at an early stage and subject to substantial uncertainties concerning the outcome of audit findings and corresponding responses.

As of December 31, 2019, we had accrued $29.2 million related to litigation and regulatory matters and $1.8 million related to indirect tax audits. The outcome of each of these may result in additional expense.

15. Transactions with Affiliates

Transactions with Affiliates

We enter into transactions with and pay certain costs on behalf of affiliates that are commonly controlled in order to reduce risk, reduce administrative expense, create economies of scale, create strategic alliances and supply goods and services to these related parties. We also sell and purchase natural gas and electricity with affiliates. We present receivables and payables with the same affiliate on a net basis in the consolidated balance sheets as all affiliate activity is with parties under common control. Affiliated transactions include certain services to the affiliated companies associated with employee benefits provided through our benefit plans, insurance plans, leased office space, administrative salaries, due diligence work, recurring management consulting, and accounting, tax, legal, or technology services. Amounts billed are based on the services provided, departmental usage, or headcount, which are considered reasonable by management. As such, the accompanying consolidated financial statements include costs that have been incurred by us and then directly billed or allocated to affiliates, as well as costs that have been incurred by our affiliates and then directly billed or allocated to us, and are recorded net in general and administrative expense on the consolidated statements of operations with a corresponding accounts receivable—affiliates or accounts payable—affiliates, respectively, recorded in the consolidated balance sheets. Transactions with affiliates for sales or purchases of natural gas and electricity, are recorded in retail revenues, retail cost of revenues, and net asset optimization revenues in the consolidated statements of operations with a corresponding accounts receivable—affiliate or accounts payable—affiliate recorded in the consolidated balance sheets.

Master Service Agreement with Retailco Services, LLC

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Prior to April 1, 2018, we were a party to a Master Service Agreement with an affiliated company owned by our Founder. The Master Service Agreement provided us with operational support services such as: enrollment and renewal transaction services; customer billing and transaction services; electronic payment processing services; customer service, and information technology infrastructure and application support services. Effective April 1, 2018, we terminated the agreement, and these operational support services were transferred back to us. See "Cost Allocations" below for further discussion of the fees paid to affiliates during the years ended December 31, 2019, 2018, and 2017 respectively.

Cost Allocations

Where costs incurred on behalf of the affiliate or us cannot be determined by specific identification for direct billing, the costs are allocated to the affiliated entities or us based on estimates of percentage of departmental usage, wages or headcount. The total net amount direct billed and allocated (to)/from affiliates was $(0.7) million, $10.3 million and $25.4 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Of the amounts directly billed and allocated from affiliates, we recorded general and administrative expense of zero, $5.9 million, and $22.0 million for the years ended December 31, 2019, 2018 and 2017, respectively. Additionally, we capitalized zero, 0.5 million, and $0.7 million of property and equipment for the application, development and implementation of various systems during the years ended December 31, 2019, 2018 and 2017, respectively.

Accounts Receivable and Payable—Affiliates

As of December 31, 2019 and 2018, we had current accounts receivable—affiliates of $2.0 million and $2.6 million, respectively, and current accounts payable—affiliates of $1.0 million and $2.5 million, respectively.

Revenues and Cost of Revenues—Affiliates

Revenues recorded in net asset optimization revenues in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017 related to affiliated sales were $2.4 million, $2.4 million, and $1.3 million, respectively, and cost of revenues recorded in net asset optimization revenues in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017 related to affiliated purchases were $0.1 million, $0.1 million and $0.1 million, respectively. These amounts are presented as net on the Consolidated Statements of Operations.

Acquisitions from Related Parties

In 2017, we acquired Perigee from our affiliate, NG&E, for total consideration of approximately $4.1 million.

In connection with the Major Energy Companies acquisition, we issued 4,000,000 shares of Class B common stock (and a corresponding number of Spark HoldCo units) to NG&E, valued at $40.0 million. In connection with the financing of the Provider Companies acquisition, we issued 1,399,484 shares of Class B common stock (and a corresponding number of Spark HoldCo units) to RetailCo, valued at $14.0 million.

In March 2018, we entered into an asset purchase agreement with an affiliate to acquire up to 50,000 RCEs for a cash purchase price of $250 for each RCE, or up to $12.5 million in the aggregate. A total of $8.8 million was paid in 2018 under the terms of the purchase agreement for approximately 35,000 RCEs, and no further material payments are anticipated. The acquisition was treated as a transfer of assets between entities under common control, and accordingly, the assets were recorded at their historical value at the date of transfer. The transaction resulted in less than $0.1 million and $7.1 million recorded in equity as a net distribution to affiliate as of December 31, 2019 and 2018, respectively.

Distributions to and Contributions from Affiliates

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During the years ended December 31, 2019, 2018 and 2017, we made distributions to affiliates of our Founder of $15.1 million, $15.5 million and $15.6 million, respectively, for payments of quarterly distributions on their respective Spark HoldCo units. During the years ended December 31, 2019, 2018 and 2017, we also made distributions to these affiliates for gross-up distributions of $19.7 million, $16.5 million, and $18.2 million, respectively, in connection with distributions made between Spark HoldCo and Spark Energy, Inc. for payment of income taxes incurred by us and settlement of the TRA.

Proceeds from Disgorgement of Stockholder Short-swing Profits

During the years ended December 31, 2019, 2018 and 2017, we recorded $0.1 million, zero, and $0.7 million, respectively, for the disgorgement of stockholder short-swing profits under Section 16(b) under the Exchange Act. The amount was recorded as an increase to additional paid-in capital in our consolidated balance sheet as of December 31, 2019, 2018 and 2017. We received $0.5 million cash during the year ended December 31, 2017 and received $0.2 million cash in February 2018.

Subordinated Debt Facility

In June 2019, we and Spark HoldCo entered into a Subordinated Debt Facility with an affiliate owned by our Founder, which allows the Company to borrow up to $25.0 million. The Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to the maximum principal amount of the Subordinated Debt Facility. Advances thereunder accrue interest at 5% per annum from the date of the advance. As of December 31, 2019 and 2018, there was zero and $10.0 million, respectively, in outstanding borrowings under the Subordinated Debt Facility. See Note 10 "Debt" for a further description of terms and conditions of the Subordinated Debt Facility.

Tax Receivable Agreement

Prior to July 11, 2019, we were party to a TRA with affiliates. Effective July 11, 2019, the Company entered into a TRA Termination and Release Agreement (the “Release Agreement”), which provided for a full and complete termination of any further payment, reimbursement or performance obligation of the Company, Retailco and NuDevco Retail under the TRA, whether past, accrued or yet to arise. Pursuant to the Release Agreement, the Company made a cash payment of approximately $11.2 million on July 15, 2019 to Retailco and NuDevco Retail. In connection with the termination of the TRA, Spark HoldCo made a distribution of approximately $16.3 million on July 15, 2019 to Retailco and NuDevco Retail under the Spark HoldCo Third Amended and Restated Limited Liability Company Agreement, as amended.

The TRA generally provided for the payment by us to affiliates of 85% of the net cash savings, if any, in U.S. federal, state and local income tax or franchise tax that we realized or would realize (or were deemed to realize in certain circumstances) in future periods as a result of (i) any tax basis increases resulting from the initial purchase by us of Spark HoldCo units from entities owned by our Founder, (ii) any tax basis increases resulting from the exchange of Spark HoldCo units for shares of Class A common stock pursuant to the Exchange Right (or resulting from an exchange of Spark HoldCo units for cash pursuant to the Cash Option) and (iii) any imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, any payments we made under the TRA. We retained the benefit of the remaining 15% of these tax savings. See Note 13 "Income Taxes" for further discussion.

For the four-quarter periods ending September 30, 2016, 2017, and 2018, we met the threshold coverage ratio required to fund the payments required under the TRA. Our affiliates, however, granted us the right to defer the TRA payment related to the four-quarter period ending September 30, 2016 until May 2018. In April, May, and December of 2018, we paid a total of $6.2 million related to our obligations under the TRA for the 2015, 2016, and 2017 tax years.

As of December 31, 2019 and 2018, we had a total liability related to the TRA of zero and $27.6 million, of which zero and $1.7 million, respectively, were classified as current liabilities.

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16. Segment Reporting

Our determination of reportable business segments considers the strategic operating units under which we make financial decisions, allocate resources and assess performance of our business. Our reportable business segments are retail electricity and retail natural gas. The retail electricity segment consists of electricity sales and transmission to residential and commercial customers. The retail natural gas segment consists of natural gas sales to, and natural gas transportation and distribution for, residential and commercial customers. Corporate and other consists of expenses and assets of the retail electricity and natural gas segments that are managed at a consolidated level such as general and administrative expenses. Asset optimization activities are also included in Corporate and other.

For the years ended December 31, 2019, 2018 and 2017, we recorded asset optimization revenues of $62.8 million, $113.7 million and $178.3 million and asset optimization cost of revenues of $60.0 million, $109.2 million and $179.0 million, respectively, which are presented on a net basis in asset optimization revenues.

The acquisitions of Perigee and the Verde Companies in 2017 and the acquisition of HIKO in 2018 had no impact on our reportable business segments as the portions of those acquisitions related to retail natural gas and retail electricity have been included in those existing business segments.

We use retail gross margin to assess the performance of our operating segments. Retail gross margin is defined as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (i) net asset optimization revenues (expenses), (ii) net gains (losses) on non-trading derivative instruments, and (iii) net current period cash settlements on non-trading derivative instruments. We deduct net gains (losses) on non-trading derivative instruments, excluding current period cash settlements, from the retail gross margin calculation in order to remove the non-cash impact of net gains and losses on these derivative instruments. Retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), as determined in accordance with GAAP.

Below is a reconciliation of retail gross margin to income (loss) before income tax expense (in thousands):

		Years Ended December 31,
(in thousands)		2019				2018				2017
Reconciliation of Retail Gross Margin to Income (loss) before taxes
Income (loss) before income tax expense		$	21,470			$	(12,315	)		$	113,809
Change in Tax Receivable Agreement Liability		—				—				(22,267		)
Gain on disposal of eRex		(4,862		)		—				—
Total other income/(expense)		(1,250		)		(749		)		(256		)
Interest expense		8,621				9,410				11,134
Operating income (loss)		23,979				(3,654		)		102,420
Depreciation and amortization		40,987				52,658				42,341
General and administrative		133,534				111,431				101,127
Less:
Net asset optimization revenue (expenses)		2,771				4,511				(717		)
Net, (losses) gain on non-trading derivative instruments		(67,955		)		(19,571		)		5,588
Net, Cash settlements on non-trading derivative instruments		42,944				(9,614		)		16,508
Retail Gross Margin		$	220,740			$	185,109			$	224,509

Financial data for business segments are as follows (in thousands):

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Year Ended December 31, 2019
	Retail Electricity				Retail Natural Gas				Corporate and Other				Eliminations				Consolidated
Total Revenues	$	688,451			$	122,503			$	2,771			$	—			$	813,725
Retail cost of revenues	552,250				62,975				—				—				615,225
Less:
Net asset optimization revenue	—				—				2,771				—				2,771
Net, Losses on non-trading derivative instruments	(66,180		)		(1,775		)		—				—				(67,955		)
Current period settlements on non-trading derivatives	41,841				1,103				—				—				42,944
Retail gross margin	$	160,540			$	60,200			$	—			$	—			$	220,740
Total Assets	$	2,524,884			$	820,601			$	341,411			$	(3,263,928	)		$	422,968
Goodwill	$	117,813			$	2,530			$	—			$	—			$	120,343

Year Ended December 31, 2018
	Retail Electricity				Retail Natural Gas				Corporate and Other				Eliminations				Consolidated
Total Revenues	$	863,451			$	137,966			$	4,511			$	—			$	1,005,928
Retail cost of revenues	762,771				82,722				—				—				845,493
Less:
Net asset optimization expense	—				—				4,511				—				4,511
Net, Losses on non-trading derivative instruments	(15,200		)		(4,371		)		—				—				(19,571		)
Current period settlements on non-trading derivatives	(8,788		)		(826		)		—				—				(9,614		)
Retail gross margin	$	124,668			$	60,441			$	—			$	—			$	185,109
Total Assets	$	1,857,790			$	649,969			$	361,697			$	(2,380,718	)		$	488,738
Goodwill	$	117,813			$	2,530			$	—			$	—			$	120,343

Year Ended December 31, 2017
	Retail Electricity				Retail Natural Gas				Corporate and Other				Eliminations				Consolidated
Total Revenues	$	657,566			$	141,206			$	(717	)		$	—			$	798,055
Retail cost of revenues	477,012				75,155				—				—				552,167
Less:
Net asset optimization expense	—				—				(717		)		—				(717		)
Net, Gains on non-trading derivative instruments	5,784				(196		)		—				—				5,588
Current period settlements on non-trading derivatives	16,302				206				—				—				16,508
Retail gross margin	$	158,468			$	66,041			$	—			$	—			$	224,509
Total Assets	$	1,218,243			$	421,896			$	281,176			$	(1,417,574	)		$	503,741
Goodwill	$	117,624			$	2,530			$	—			$	—			$	120,154

Significant Customers

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For each of the years ended December 31, 2019, 2018 and 2017, we did not have any significant customers that individually accounted for more than 10% of our consolidated retail revenue.

Significant Suppliers

For each of the years ended December 31, 2019, 2018 and 2017, we had one, two, and two significant suppliers that individually accounted for more than 10% of our consolidated retail cost of revenues and net asset optimization revenues. For each of the years ended December 31, 2019, 2018 and 2017, these suppliers accounted for 10%, 28% and 20% of our consolidated cost of revenue.

17. Equity Method Investment

Investment in eREX Spark Marketing Co., Ltd

Prior to November 2019, we, together with eREX Co., Ltd., a Japanese company, were party to an agreement ("eREX JV Agreement") for a joint venture, eREX Spark Marketing Co., Ltd ("ESM"). As part of this agreement, we made contributions of 156.4 million Japanese Yen, or $1.4 million, for a 20% ownership interest in ESM. We were entitled to share in 30% of the dividends distributed by ESM for the first year a qualifying dividend was paid and for the subsequent four years thereafter. After this period, dividends were to be distributed proportionately with the equity ownership of ESM. ESM's board of directors consists of four directors, one of whom was appointed by us. In November 2019, Spark HoldCo, LLC entered into a share purchase agreement with eREX Co., Ltd. In accordance with the agreement, Spark HoldCo, LLC sold its shares which represented 20% ownership interest in ESM for $8.4 million. The disposal of ESM resulted in a non-recurring gain of $4.9 million for the year ended December 31, 2019. Based on our significant influence, as reflected by the 20% equity ownership and 25% control of the ESM board of directors, we recorded the investment in ESM as an equity method investment.

Our investment in ESM was $3.1 million as of December 31, 2018, reflecting contributions made by us through December 31, 2018 and our proportionate share of earnings as determined under the HLBV method as of December 31, 2018, and recorded in other assets in the consolidated balance sheet. There were no basis differences between our initial contribution and the underlying net assets of ESM. We recorded our proportionate share of ESM's earnings of $0.8 million and $0.5 million in our consolidated statement of operations for the years ended December 31, 2019 and 2018, respectively.

18. Subsequent Events

Declaration of Dividends

On January 21, 2020, we declared a quarterly dividend of $0.18125 per share to holders of record of our Class A common stock on March 2, 2020, which will be paid on March 16, 2020.

We also declared a quarterly cash dividend in the amount of $0.546875 per share to holders of record of the Series A Preferred Stock on April 1, 2020. The dividend will be paid on April 15, 2020.

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Supplemental Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data is as follows:

	Quarter Ended
	2019
	December 31, 2019				September 30, 2019				June 30, 2019				March 31, 2019
	(In thousands, except per share data)
Total Revenues	$	186,183			$	207,087			$	177,749			$	242,706
Operating income (loss)	633				46,095				(28,569		)		5,820
Net (loss) income	(724		)		37,676				(25,484		)		2,745
Net (loss) income attributable to Spark Energy, Inc. stockholders	(751		)		15,534				(7,115		)		782
Net (loss) income attributable to stockholders of Class A common stock	(2,762		)		13,508				(9,142		)		(1,245		)
Net (loss) income attributable to Spark Energy, Inc. per common share—basic	(0.19		)		0.94				(0.64		)		(0.09		)
Net (loss) income attributable to Spark Energy, Inc. per common share—diluted	(0.19		)		0.93				(0.73		)		(0.09		)

	Quarter Ended
	2018
	December 31, 2018				September 30, 2018				June 30, 2018				March 31, 2018
	(In thousands, except per share data)
Total Revenues	$	228,514			$	258,475			$	232,251			$	286,688
Operating (loss) income	(11,795		)		25,454				28,941				(46,254		)
Net (loss) income	(15,315		)		18,827				23,927				(41,831		)
Net (loss) income attributable to Spark Energy, Inc. stockholders	(5,633		)		6,767				8,785				(11,105		)
Net (loss) income attributable to stockholders of Class A common stock	(7,660		)		4,740				6,757				(13,132		)
Net income (loss) attributable to Spark Energy, Inc. per common share—basic	0.56				0.35				0.51				(1.00		)
Net income (loss) attributable to Spark Energy, Inc. per common share—diluted	0.58				0.35				0.51				(1.04		)

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Annual Report on Form 10-K. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost benefit relationship of possible controls and procedures. Based on this evaluation, management concluded that our disclosure controls and procedures were effective as of December 31, 2019 at the reasonable assurance level.

Management's Annual Report on Internal Control Over Financial Reporting

See "Management's Report on Internal Control Over Financial Reporting" under Item 8 of this Annual Report on Form 10-K.

Attestation Report of the Independent Registered Public Accounting Firm

Our independent registered public accounting firm, Ernst & Young LLP, has provided an attestation report on the Company’s internal control over financial reporting as of December 31, 2019.

Changes in Internal Control over Financial Reporting

There was no change in our internal control over financial reporting identified in connection with the evaluation required by Rule 13a-15(d) and 15d-15(d) of the Exchange Act that occurred during the three months ended December 31, 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

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PART III.

Item 10. Directors, Executive Officers and Corporate Governance

Information as to Item 10 will be set forth in the Proxy Statement for the 2020 Annual Meeting of Shareholders (the “Annual Meeting”) and is incorporated herein by reference.

Item 11. Executive Compensation

Information as to Item 11 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management, and Related Stockholder Matters

Except as provided below, information as to Item 12 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Equity Compensation Plan Information

The following table shows information about our Class A common stock that may be issued under the Spark Energy, Inc. Amended and Restated Incentive Plan (the “Incentive Plan”) as of December 31, 2019.

Plan category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)(2))
Equity compensation plans approved by the security holders	1,277,210		1,613,364
Equity compensation plans not approved by the security holders	—		—
Total	1,277,210		1,613,364

(1) This column reflects the maximum number of shares of Class A common stock that may be issued under outstanding and unvested restricted stock units ("RSUs") at December 31, 2019. No stock options or warrants have been granted under the Incentive Plan.

(2) This column reflects the total number of shares of Class A common stock remaining available for issuance under the LTIP.

The Incentive Plan is the only plan under which our equity securities are authorized for issuance. The Incentive Plan was approved by our shareholder prior to our initial public offering and was approved by our public shareholders in 2019. Please read Note 12 to our consolidated financial statements, entitled "Stock-Based Compensation" for a description of the Incentive Plan.

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Item 13. Certain Relationships and Related Transactions, and Director Independence

Information as to Item 13 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

Information as to Item 14 will be set forth in the Proxy Statement for the Annual Meeting and is incorporated herein by reference.

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PART IV.

Item 15. Exhibits, Financial Statement Schedules

(1) The consolidated financial statements of Spark Energy, Inc. and its subsidiaries and the report of the independent registered public accounting firm are included in Part II, Item 8 of this Annual Report.

(2) All schedules have been omitted because they are not required under the related instructions, are not applicable or the information is presented in the consolidated financial statements or related notes.

(3) The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this Annual Report.

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INDEX TO EXHIBITS
		Incorporated by Reference
Exhibit	Exhibit Description	Form	Exhibit Number		Filing Date	SEC File No.
2.1#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet, dated as of May 3, 2016.	10-Q		2.1	5/5/2016	001-36559
2.2#	Membership Interest Purchase Agreement, by and among Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC and National Gas & Electric, LLC, dated as of May 3, 2016.	10-Q		2.2	5/5/2016	001-36559
2.3#	Amendment No. 1 to the Membership Interest Purchase Agreement, dated as of July 26, 2016, by and among Spark Energy, Inc., Spark HoldCo, LLC, Provider Power, LLC, Kevin B. Dean and Emile L. Clavet.	8-K		2.1	8/1/2016	001-36559
2.4#	Membership Interest and Stock Purchase Agreement, by and among Spark Energy, Inc., CenStar Energy Corp. and Verde Energy USA Holdings, LLC, dated as of May 5, 2017.	10-Q		2.4	5/8/2017	001-36559
2.5	First Amendment to the Membership Interest and Stock Purchase Agreement, dated July 1, 2017, by and among Spark Energy, Inc., CenStar Energy Corp., and Verde Energy USA Holdings, LLC.	8-K		2.1	7/6/2017	001-36559
2.6#	Agreement to Terminate Earnout Payments, effective January 12, 2018, by and among Spark Energy, Inc., CenStar Energy Corp., Woden Holdings, LLC (fka Verde Energy USA Holdings, LLC), Verde Energy USA, Inc., Thomas FitzGerald, and Anthony Mench.	8-K		2.1	1/16/2018	001-36559
2.7#	Asset Purchase Agreement, dated March 7, 2018, by and between Spark HoldCo, LLC and National Gas & Electric, LLC	10-K		2.7	3/9/2018	001-36559
2.8#	Asset Purchase Agreement by and between Spark HoldCo, LLC and Starion Energy Inc., Starion Energy NY Inc. and Starion Energy PA Inc., dated October 19, 2018.	8-K		2.1	10/25/2018	001-36559
3.1	Amended and Restated Certificate of Incorporation of Spark Energy, Inc.	8-K		3.1	8/4/2014	001-36559
3.2	Amended and Restated Bylaws of Spark Energy, Inc.	8-K		3.2	8/4/2014	001-36559
3.3	Certificate of Designations of Rights and Preferences of 8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock.	8-A		5	3/14/2017	001-36559
4.1*	Description of Capital Stock of Spark Energy, Inc.
4.2	Class A Common Stock Certificate	S-1		4.1	6/30/2014	333-196375
4.3	Convertible Subordinated Promissory Note of Spark HoldCo, LLC and Spark Energy, Inc. dated July 8, 2015 payable to Retailco Acquisition Co, LLC	10-Q		10.8	8/13/2015	001-36559
4.4	Convertible Subordinated Promissory Note of Spark HoldCo, LLC and Spark Energy, Inc. dated July 31, 2015 payable to Retailco Acquisition Co, LLC	10-Q		10.9	8/13/2015	001-36559

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4.5	Promissory Note of CenStar Energy Corp., effective July 1, 2017, payable to Verde USA Holdings, LLC.	8-K		10.1	7/6/2017	001-36559
4.6	Amended and Restated Promissory Note of CenStar Energy Corp., effective January 12, 2018, payable to Woden Holdings, LLC.	8-K		10.2	1/16/2018	001-36559
4.7	Promissory Note of CenStar Energy Corp., effective January 12, 2018, payable to Woden Holdings, LLC.	8-K		10.1	1/16/2018	001-36559
10.1	Credit Agreement, dated as of May 19, 2017, among Spark Energy, Inc., Spark HoldCo, LLC, Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, CenStar Operating Company, LLC, Oasis Power, LLC, Oasis Power Holdings, LLC, Electricity Maine, LLC, Electricity N.H., LLC, Provider Power Mass, LLC, Major Energy Services LLC, Major Energy Electricity Services LLC, Respond Power LLC and Perigee Energy, LLC as Co-Borrowers, Coöperatieve Rabobank U.A., New York Branch, as Administrative Agent, an Issuing Bank and a Bank, and Coöperatieve Rabobank U.A., New York Branch and BBVA Compass, as Joint Lead Arrangers and Sole Bookrunner, and the Other Financial Institutions Signatory Thereto.	8-K		10.1	5/24/2017	001-36559
10.2	Amendment No. 1 to the Credit Agreement, dated as of November 2, 2017, among Spark HoldCo, LLC, Spark Energy, LLC, Spark Energy Gas, LLC, CenStar Energy Corp, CenStar Operating Company, LLC, Oasis Power, LLC, Oasis Electricity Maine, LLC, Electricity N.H., LLC, Provider Power Mass, LLC, Major Energy Services, LLC, Perigee Energy, LLC, Verde Energy USA, Inc. as Co-Borrowers.	10-Q		10.1	11/3/2017	001-36559
10.3	Amendment No. 2 to the Credit Agreement, dated as of July 17, 2018, by and among Spark Energy, Inc., the Co-Borrowers, the Banks party thereto, and Brown Borthers Harrisman & Co., as existing bank.	8-K		10.1	7/20/2018	001-36559
10.4	Amendment No. 3 to the Credit Agreement, dated as of June 13, 2019, by and among Spark Energy, Inc., the Co-Borrowers, the Issuing Banks party thereto, Coӧperatieve Rabobank U.A., New York Branch, as agent, and the Banks party thereto.	8-K		10.1	6/18/2019	001-36559
10.5	Tax Receivable Agreement, dated as of August 1, 2014, by and among Spark Energy, Inc., Spark HoldCo LLC, NuDevco Retail Holdings, LLC, NuDevco Retail, LLC and W. Keith Maxwell III.	8-K		10.2	8/4/2014	001-36559
10.6+	Master Service Agreement, effective as of January 1, 2016, by and among Spark HoldCo, LLC, Retailco Services, LLC, and NuDevco Retail,. LLC.	10-K		10.6	3/24/2016	001-36559
10.7†	Spark Energy, Inc. Long-Term Incentive Plan	S-8		4.3	7/31/2014	333-197738
10.8†	Spark Energy, Inc. Amended and Restated Long-Term Incentive Plan.	10-Q		10.3	11/10/2016	001-36559
10.9†	Form of Restricted Stock Unit Agreement	S-1		10.4	6/30/2014	333-196375
10.10†	Form of Notice of Grant of Restricted Stock Unit	S-1		10.5	6/30/2014	333-196375
10.11†	Form of Notice of Grant of Restricted Stock Unit (Change in Control Restricted Stock Units).	10-Q		10.5	8/3/2018	001-36559

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10.12	Spark HoldCo. Third Amended and Restated Limited Liability Agreement, dated as of March 15, 2017, by and among Spark Energy, Inc., Retailco, LLC and NuDevco Retail, LLC.	10-Q		10.1	5/8/2017	001-36559
10.13	Amendment No. 1, dated as of January 26, 2018, to Third Amended and Restated Limited Liability Company Agreement of Spark Holdco, LLC.	8-K		10.1	1/26/2018	001-36559
10.14†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and W. Keith Maxwell III.	8-K		10.5	8/4/2014	001-36559
10.15†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and Nathan Kroeker.	8-K		10.6	8/4/2014	001-36559
10.16†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and Gil Melman.	8-K		10.9	8/4/2014	001-36559
10.17†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and James G. Jones II.	8-K		10.10	8/4/2014	001-36559
10.18†	Indemnification Agreement, dated August 1, 2014, by and between Spark Energy, Inc. and Kenneth M. Hartwick.	8-K		10.12	8/4/2014	001-36559
10.19†	Indemnification Agreement, dated May 25, 2016, by and between Spark Energy, Inc. and Jason Garrett.	8-K		10.2	5/27/2016	001-36559
10.20†	Indemnification Agreement, dated May 25, 2016, by and between Spark Energy, Inc. and Nick W. Evans, Jr.	8-K		10.1	5/27/2016	001-36559
10.21†	Indemnification Agreement, dated June 2, 2016, by and between Spark Energy, Inc. and Robert Lane.	8-K		10.3	6/3/2016	001-36559
10.22	Registration Rights Agreement, dated as of August 1, 2014, by and among Spark Energy, Inc., NuDevco Retail Holdings, LLC and NuDevco Retail LLC.	8-K		10.4	8/4/2014	001-36559
10.23	Transaction Agreement II, dated as of July 30, 2014, by and among Spark Energy, Inc., Spark HoldCo, LLC, NuDevco Retail LLC, NuDevco Retail Holdings, LLC, Spark Energy Ventures, LLC, NuDevco Partners Holdings, LLC and Associated Energy Services, LP.	8-K		4.1	8/4/2014	001-36559
10.24†	Employment Agreement, dated April 15, 2015, by and between Spark Energy, Inc. and Nathan Kroeker.	8-K		10.1	4/20/2015	001-36559
10.25†	Employment Agreement, dated April 15, 2015, by and between Spark Energy, Inc. and Gil Melman.	8-K		10.4	4/20/2015	001-36559
10.26†	Employment Agreement, dated August 3, 2015, by and between Spark Energy, Inc. and Jason Garrett.	8-K		10.1	8/4/2015	001-36559
10.27†	Amended and Restated Employment Agreement, dated June 2, 2016, by and between Spark Energy, Inc. and Robert Lane.	8-K		10.1	6/3/2016	001-36559
10.28†	Amended Employment Agreement between Spark Energy, Inc. and Nathan Kroeker dated August 1, 2018.	10-Q		10.2	8/3/2018	001-36559
10.29†	Amended and Restated Employment Agreement between Spark Energy, Inc. and Jason Garrett dated August 1, 2018.	10-Q		10.3	8/3/2018	001-36559
10.30†	Amended and Restated Employment Agreement between Spark Energy, Inc. and Gil Melman dated August 1, 2018.	10-Q		10.4	8/3/2018	001-36559

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10.31†	Transition and Resignation Agreement and Mutual Release of Claims, by and between Spark Energy, Inc. and Gil Melman, dated December 13, 2018.	10-Q		10.1	12/14/2018	001-36559
10.32	Termination Agreement, dated March 7, 2018, by and among Spark HoldCo, LLC, Retailco Services, LLC and NuDevco Retail, LLC.	10-K		10.43	3/9/2018	001-36559
10.33†	Spark Energy, Inc. Second Amended and Restated Long Term Incentive Plan.	8-K		10.1	5/23/2019	001-36559
10.34	Amended and Restated Subordinated Promissory Note of Spark HoldCo, LLC and Spark Energy, Inc., dated June 13, 2019.	8-K		10.2	6/18/2019	001-36559
10.35†	Employment Agreement, dated June 14, 2019, by and between Spark Energy, Inc. and James G. Jones II.	8-K		10.3	6/18/2019	001-36559
10.36	TRA Termination and Release Agreement, dated July 11, 2019, by and among Spark Energy, Inc., Spark HoldCo, LLC, Retailco, LLC, NuDevco Retail, LLC and W. Keith Maxwell III.	8-K		10.1	7/17/2019	001-36559
10.37 †	Indemnification Agreement, dated August 29, 2019, by and among Spark Energy, Inc. and Amanda Bush	8-K		10.1	8/30/2019	001-36559
10.38	Transition and Resignation Agreement and Mutual Release of Claims, by and between Spark Energy, Inc. and Jason Garrett, dated September 25, 2019	8-K		10.1	9/27/2019	001-36559
16.1	Letter of KPMG LLP, dated August 16, 2018 to the SEC	8-K		16.1	8/16/2018	001-36559
21.1*	List of Subsidiaries of Spark Energy, Inc.
23.1*	Consent of EY
23.2 *	Consent of KPMG
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32**	Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Schema Document.
101.CAL*	XBRL Calculation Document.
101.LAB*	XBRL Labels Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.
101.DEF*	XBRL Definition Linkbase Document.

* Filed herewith

** Furnished herewith

† Compensatory plan or arrangement

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+ Portions of this exhibit have been omitted and filed separately with the SEC pursuant to an order granting confidential treatment.

# The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.

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Item 16. Form 10-K Summary

None.

SIGNATURES

Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

March 5, 2020	Spark Energy, Inc.
	By:		/s/ James G. Jones II
			James G. Jones II
			Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities indicated on March 5, 2020:
	By:		/s/ Nathan Kroeker
			Nathan Kroeker
			President and Chief Executive Officer (Principal Executive Officer)
			/s/ W. Keith Maxwell III
			W. Keith Maxwell III
			Chairman of the Board of Directors, Director
			/s/ James G. Jones II
			James G. Jones II
			Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
			/s/ Nick Evans Jr.
			Nick Evans Jr.
			Director
			/s/ Kenneth M. Hartwick
			Kenneth M. Hartwick
			Director
			/s/ Amanda Bush
			Amanda Bush
			Director

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